201 annual report - laricina energy rouse, team lead, production operations engineering we are an in...

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2012 AnnuAl RepoRt

We Produce

Value I Growth I Innovation

Head OfficeLaricina energy Ltd.eAst toweR, FIFtH AVenue plAcesuIte 800, 425 – 1st stReet swcAlgARy, Ab t2p 3l8 P i 403.750.0810f i 403.263.0767

Wabasca cOmmunity engagement OfficeLaricina energy Ltd.2155 MIstAssInIy RoAdp.o. box 540wAbAscA, Ab t0g 2K0

P i 780.891.3352f i 780.891.3359

Laricinaenergy.cOm

Forward-Looking Statements

This annual report contains certain “forward-looking statements” under applicable securities laws and includes such statements about Laricina Energy Ltd.’s plans that are based on assumptions and that involve risk and uncertainties. Actual results may differ materially. Refer to page 46 for additional information on forward-looking statements.

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This isLaricina

from prospects to recognized assets. from simulation and testing to drilling and production. from ideas to innovation. from resources to reserves. since its founding in 2005, Laricina’s story has been one of acting on ideas, of fulfilling commitments – of producing.

Germain Commercial Demonstration Project (CDP)

2 We Produce Value 4 We Define Growth 6 We Foster Innovation11 We Create Decades of

Future Growth and Value12 President’s Letter18 We Produce Bitumen from

the Grosmont at Saleski26 We Are Building at Germain34 We Unlock Growth Opportunities36 We Advance In Situ Technologies

and Innovation38 We Engage Communities and

Operate Safe Projects

40 We Have Built a Dedicated Team41 Reserves and Resources46 Management’s Discussion and Analysis67 Independent Auditors’ Report68 Consolidated Financial Statements72 Notes to the Consolidated

Financial Statements96 Laricina Mangement Team97 Laricina Board of Directors98 Corporate InformationIBC Glossary and Abbreviations

GlossaryAESRD Alberta Environment and Sustainable Resource Development

C-SAGD cyclic steam-assisted gravity drainage

CSS cyclic steam stimulation

CDP commercial demonstration project

CPF central processing facility

ERCB Energy Resources Conservation Board

ESEIEH Enhanced Solvent Extraction Incorporating Electromagnetic Heating

GLJ GLJ Petroleum Consultants Ltd., independent engineering and geological services firm

HSE health, safety and environment

IFRS International Financial Reporting Standards

OASIS Open-Access Simulation Integrated System

PHARM Passive Heat-Assisted Recovery Method

SAGD steam-assisted gravity drainage

SC-SAGD solvent-cyclic steam-assisted gravity drainage

SOR steam-to-oil ratio

abbreviaTions°C degrees Celsius

% percent

bbls barrels

bbls/d barrels per day

D darcy

kH horizontal permeability

km kilometre(s)

kV kilovolt(s)

kV vertical permeability

m metre(s)

m3 metres cubed

mmbbls million barrels

MMBtu million British thermal units

MPa megapascal(s)

PV10 net present value, before tax, 10 percent discount

square-km square kilometres

Gord Rouse, Team Lead, Production Operations Engineering

We are an in situ oil sands producer, a pioneer in our two current project areas. At Saleski, Laricina has demonstrated commercial production from the Grosmont carbonate formation. At Germain, we are among the first movers in the Grand Rapids sands, with commercial operations targeted for start-up in 2013. Our growth properties are located in established and emerging plays.

Saleski pilot project

1

(1) GLJ Report effective December 31, 2012. See Reserves and Resources starting on page 41 and Glossary and Abbreviations on the inside back cover.

2 2012 AnnuAl RepoRt2

We Produce Value

500,000 bbls/d net production potential

bbls probable reserves 466 Million (1)

4.2 Billion bbls contingent resources (best estimate) (1)

$543 Million PV10 before tax future

net revenue of probable reserves (1)

This is Laricina’s path to value creation. Our asset base holds 466 million net barrels of probable reserves(1), 4.2 billion net barrels of contingent resources (best estimate)(1) and 0.3 billion net barrels of prospective resources (best estimate)(1) at year-end 2012 (as determined by GLJ Petroleum Consultants Ltd. (GLJ)). The cyclic steam-assisted gravity drainage (C-SAGD) recovery process at Saleski is delivering commercial well productivity. The Germain commercial demonstration project (CDP) is on schedule and budget, targeting start-up in mid-2013.

Future expansion phase designs will be refined based on what we observe and what we learn. Value-enhancing innovations are being tested, patented and field-proven. Major infrastructure including roads, natural gas and electrical power is complete or in progress, and we are advancing plans on a pipeline system.

$8.5 Billion PV10 before tax (1)

future net revenue of contingent resources

(best estimate)

3Laricina EnErgy LtD. 3

Resources are transformed into reserves, new reservoirs are proven, drilling, extraction and development models are substantiated by performance, infrastructure is put in place, bitumen is produced and marketed throughout North America, uncertainties and risks are reduced.

33Laricina EnErgy LtD.

Lane Becker, Director, Drilling, Completions & Logistics

4 2012 annuaL rEport

Grosmont subcrop

McMurray bitumen trend > 10 metres

Grand Rapids bitumen trend > 10 metres

Nisku subcrop

Grosmont bitumen trend > 40 metres

We deFine Growth

The reservoir is the foundation for growth. Laricina’s assets include the familiar McMurray oil sands, the emerging Grand Rapids oil sands and two carbonate formations – the Grosmont and Winterburn. Once resources are delineated and tested, development begins at a relatively small scale, in order to manage capital risk and to apply what is learned to future phases. Meanwhile, future phases are being advanced at the regulatory and engineering levels.

Laricina’s growth is focused on its two current project areas, Saleski and Germain. The Saleski pilot is producing bitumen from the Grosmont carbonate formation and construction of the 10,700-barrel-per-day Phase 1 commercial phase is expected to begin this year. Construction of Germain’s first phase, a 5,000-barrel-per-day project, is nearing completion and steam injection into the Grand Rapids sands is scheduled for mid-2013 with production commencing later in the year.

Laricina’s asset portfolio has been shaped to provide exposure to multiple large oil sands opportunities. All properties are held at high working interest with operatorship and contain high-quality reservoirs capable of driving our growth.

Imagery © 2013 TerraMetrics Map data © 2013 Google

Gordon Lee, Senior Geologist

Laricina properties

Laricina EnErgy LtD. 5

Saleski

Burnt Lakes

Future Roadway

House River

Thornbury West

Portage

Thornbury

Germain

Wabasca-Desmarais

Boiler Rapids

Fort McMurray

PoplarCreekConn

Creek

Cheecham Terminal

Chip LakeRoad

ProposedStony Mountain Pipeline


We FoSTer InnoVatIon

All of the Company’s assets are commercially viable using established, available technology. Technological edge is not about getting at the asset, it is about getting more from the asset. Our innovations are directed at generating measurable, sustainable economic uplift from our assets.

Laricina’s approach to innovation and technology focuses on achieving

economic efficiencies for our shareholders. Reducing the steam-to-oil ratio (SOR) by adding solvents or capturing surplus heat from adjoining zones saves on energy input costs. Improvements in well pad design drive down our costs throughout the supply chain. Lower energy usage per barrel of bitumen produced improves environmental performance.


We are leaders in innovation and have been since the Company’s beginning. Continuous improvements to bitumen extraction models, processes, design and equipment are key to reducing costs, maximizing productivity and long-term resource recovery, and commercializing new opportunities.

Kevin Meyer, Manager, Drilling and Completions


2006•Raised$95millionfromtwoequityfinancings•AcquiredGermainproperty,Laricina’s

largestassetandapioneeringGrandRapidsFormationoilsandsplay

•AcquiredSaleskiandbeganstudyandanalysisoftheGrosmontcarbonatereservoir

•Completedfirstresourceassessmentofassetportfolio,with1.2billionbarrelsofnetcontingentresources

•ResearchanddevelopmentprojectsbeganwiththeUniversityofCalgary

2008

•Invested$133millionincapitalassets•Expandedteamto46employeesandopened

Wabascaoffice•Built21-kmall-weatherroadtoGermain•Submittedapplicationfor1,800-barrel-per-

dayGrosmontpilotatSaleski•DrilledfirsthorizontalwellatSaleskipilot,

initiateddrillingofsecondhorizontalwell•BecameafoundingmemberofInSituOil

SandsAlliance(IOSA)

•Laricinafounded•Raised$77millioninprivateequity•BuiltsolidmanagementteamandBoardof

Directors;staffcountof8personnel•PoplarCreekleasepurchasedasfirstasset

2005

•Raised$198millionfromtwoequityfinancings•Added$70milliontocapitalassets•SubmittedregulatoryapplicationsforGermain

pilotandSaleskinon-thermalsolventrecoveryfieldtest

•PhysicalsiteworkbeganatGermain•Firstseismicprograminitiated,acquiringmore

than190kmof2-Dseismic•Firstcoredrillingprogram,comprisedof71

delineationwellsacrossassetbase

2007

•Prudentlymanagedcapitalthroughworldwideeconomicstorm

•BeganSaleskipilotconstruction:completedwellpad,drilledservicewells,preparedplantsiteandbeganplacingfacilitycomponents;constructionworkforcepeakedat350

•AmendedGermainplantobecomea5,000-barrel-per-dayCDPwithsolventinjectionandrecycling

•Completed$84millionequityfinancing•DrilledthreedelineationwellsatBurntLakes,a

newGrosmontcarbonateprospect

2009


2010•FiledregulatoryapplicationforPhase1

expansionof10,700barrelsperdayatSaleski•Completednearly$342millionequity

financings•Laricinaexecutiverepresentativebecame

ChairofUniversityofCalgary’sSolventHeat-AssistedRecoveryProgram(SHARP)

•Filedpatentapplicationforin situEnhancedSolventExtractionIncorporatingElectromagneticHeating(ESEIEH)recoveryprocesses

•Initiatedsteaminjectioninfirstwell-pairatSaleskitotestGrosmontDzone

•Firstrecognitionofreserves:36millionnetbarrelsofprobablereservesassignedtoGermainGrandRapids

•ProducedbitumenfromtheGrosmontCandDzones

•CommenceddrillingtwoadditionalwellsatSaleskiintheGrosmontC

•ReceivedfirstpatentforthePassiveHeat-AssistedRecoveryMethod(PHARM)process

•Drilledsixhorizontalwell-pairsatGermainCDP,completedcivilconstruction

•Raisedapproximately$520millionthroughtwoprivateequityfinancings

•BitumenblendsalesfromSaleskiwereapproximately55,500grossbarrelsatyear-end

•Atyear-end,probablereservesincreasedforGermainGrandRapidsto387millionnetbarrels

2011

•FirststeamatGermainCDPscheduledformid-year,withfirstproductiontofollowshortlythereafter

•Completewinter3-DseismicprogramatConnCreekandBurntLakesgrowthproperties

•Continuepilotoptimization,debottleneckingandproductionramp-upatSaleski

•SaleskiPhase1front-endengineeringanddesignstudyscheduledtobecomplete;detailedengineeringanddesign,orderingoflong-leaditems,drillingandconstructionscheduledtocommence

•RegulatoryapprovalforSaleskiPhase1,GermainPhase2andtheStonyMountainPipelineexpected

2013

This timeline represents Laricina’s view of its future plans that are based on assumptions that involve risks and uncertainties. Refer to page 46 for additional information.2012

•DemonstratedcommercialityinthecarbonatesthroughC-SAGDatSaleski

•Saleskiachievedmilestoneof100,000thgrossbarrelofbitumeninAugust,withcumulativetotalof186,000grossbarrelsreachedbyyear-end

•BegansolventtestingatSaleski•FiledregulatoryupdateforSaleskiPhase1

touseC-SAGD,withfirststeamandproductiontargetedforlate2015

•Drilledandcompletedremainingfourwell-pairsatGermain,achieving20percentcapitalcostreduction

•FiledregulatoryapplicationfortheStonyMountainPipeline

•Rampedupstaffingandendedtheyearwith154full-timeemployees

•Filedpatentapplicationforwellpadmodularization

•Atyear-end,Saleskiassignedfirstprobablereserves,totalling76millionnetbarrels

2015

•Targetcombinednetinstalledcapacityof100,000barrelsperdayatGermainandSaleski

•Continueallaspectsoftechnicalandfieldworkforfurtherexpansionto500,000barrelsperdaygrossproduction

•Continuedevelopmentofremaininggrowthproperties

2020+

•AdvanceSC-SAGDunderstandingandimproverecovery

•Advancedevelopmentatothercoreproperties

•ContinueexplorationandresourcevalidationatBurntLakes

•Productionramp-upatSaleskiPhase1expected

•FirstproductionatGermainPhase2targeted

•AdvanceunderstandingofWinterburncarbonatesatGermain

•FuturephasesatSaleskiandGermainadvance

2016-2019•SaleskiPhase1construction

continues,starttoincreasestaffinanticipationofstart-upthefollowingyear

•Ramp-upSAGDproductionatGermainCDP,establishproductionparametersandimplementsolvent-cyclicSAGD(SC-SAGD)

•ScheduledlaunchofdetailedengineeringanddesignforGermainPhase2

•FileregulatoryapplicationforSaleskiPhase2

•ExpectfirstprovedreservesatGermainCDP

2014

•CompletionofSaleskiPhase1constructiontargetedformid-year,followedbysteaminjectionandproduction,withgrossinstalledproductioncapacityatSaleskinow12,500barrelsperday

•Continuefacilityandprocessoptimizationatallprojectsincludingfocusoninnovationandtechnologytoreduceoperatingcostsandenvironmentalfootprint

This timeline represents Laricina’s view of its future plans that are based on assumptions that involve risks and uncertainties. Refer to page 46 for additional information.


From left to right: Dean Setoguchi (seated), Senior Vice President and Chief Financial Officer; David Safari, Vice President Facilities; Derek Keller (seated), Vice President Production; James Hand, Senior Vice President Operations and Chief Operating Officer; Glen Schmidt (seated), President and Chief Executive Officer; Marla Van Gelder (seated), Vice President Corporate Development; Karen Lillejord, Vice President Finance and Controller

Laricina has created a platform for growth and value creation since its founding in 2005, and we believe our phased approach to expansion at Saleski and Germain creates a visible pathway for adding production and reserves. Targeted milestones include 42,500 barrels per day of net installed capacity in 2016, with regulatory applications in progress and 100,000 barrels per day net capacity targeted in 2020 at Germain and Saleski alone.

Laricina believes it has a world-class resource base with existing and potential in situ projects in four sand and two carbonate formations. Our growth platform includes extraction methods and operating facilities that improve with each iteration, innovations that lever productivity and installed capacity, and steadily improving infrastructure to support future expansions at high capital efficiency. The longer we operate the better we become. Growth…and value.

We creATe DecaDes of future Growth anD Value

11Laricina EnErgy LtD. 12 2012 annuaL rEport

presIDent’sleTTer


Our vision to establish Laricina as a leader in advancing the commercialization of the Grosmont and Grand Rapids in west Athabasca resulted in several significant steps taken in 2012, from the demonstration of commercial rates in the Grosmont carbonate formation at Saleski, to advancing our construction at Germain, accessing the Grand Rapids sand formation.

Saleski Catalyst – Demonstration of Commercial RatesThe defining moment at Saleski during 2012 was the demonstration of commercial rates from the Grosmont carbonate formation at our Saleski pilot. The Grosmont is one of the largest oil-bearing resources in Alberta, second only to the McMurray sands.

Gravity drainage is the recovery mechanism used for in situ bitumen extraction. Heat is delivered and the oil is mobilized and drained. Each reservoir requires a particular engineering approach to deliver the heat and extract the oil using vertical or horizontal wells, single or separate injection and production wells, and various steaming models. Different operators are applying different configuration and extraction methods in various geological horizons. Our work in the Grosmont is ground-breaking. Results from our pilot have enabled us to put the pieces of the puzzle together. There is no question the reservoir is of high quality, but the missing piece until now was a commercial design for oil extraction.

At Saleski, the character of the Grosmont has determined that a single horizontal well operated cyclically is best. We have moved beyond traditional dual-well steam-assisted gravity drainage (SAGD), adapting our drilling and completions model and steam injection method, to fit the unique characteristic of the rock. We have confirmed that C-SAGD is best for start-up and initial production of bitumen from the Grosmont at Saleski.

Along with C-SAGD, other modifications to our design include moving away from over-balanced drilling with a cased-hole completion (standard in the oil sands), to near-balanced drilling with open-hole completion and stimulation to remove formation damage around the wellbore (a simplification we learned from our first wells when drilling over-balanced). As we optimized our well design and thermal recovery scheme for C-SAGD, production from the wells at our pilot increased, as evidenced by peak rate production exceeding 1,200 gross barrels per day in our second well in the Grosmont C Formation.

We have created an economic case in the Grosmont where our initial performance has been enhanced through refinement, resulting in a new, competitive energy supply. At Saleski, we have an achievable and economic vision that includes continued production, testing and optimization at the pilot, and a 10,700-barrel-per-day gross production expansion targeted to be on-stream in 2015.

The Saleski-Germain PlatformScale, resource quality and infrastructure drive competitive advantage in a resource play, particularly an oil sands resource play. With gross production potential of more than 500,000 barrels per day in two neighbouring projects, Saleski and Germain provide one of the industry’s largest in situ platforms. The pending approval of Laricina’s Stony Mountain Pipeline (along with the Grand Rapids Pipeline, a crude oil and diluent pipeline jointly proposed by TransCanada Corporation and Phoenix Energy Holdings Limited), ownership in the road system from Wabasca to our projects, and steady progress of main-line power supply are paving the way for these projects to be fully serviced by infrastructure. This will benefit both our projects and the greater west Athabasca area for decades.

WE HAVE CREATED An ECOnOMIC CASE

In THE GROSMOnT WHERE OuR InITIAL

PERFORMAnCE HAS bEEn EnHAnCED

THROuGH REFInEMEnT, RESuLTInG In A

nEW, COMPETITIVE EnERGy SuPPLy.


Work at the Germain CDP steadily progressed during 2012 and we continue on schedule and budget, with first steam targeted for mid-2013 and first production estimated for later in the year. Our work at the Germain CDP has reinforced our step-wise and continuous approach to execution. We have achieved a cost reduction of 20 percent in the last four well-pairs of the ten well-pairs drilled at Germain. Well pad optimization led to improvements in the manifold system and pipe rack/module design, for which a patent application has been filed. The more efficient sizing that resulted allows us to expand our module sourcing and transportation options beyond the province to eastern Canada, the united States and overseas. We estimate that by accessing different markets, we can achieve savings in the range of 15 to 30 percent, which will have significant positive impact on capital costs.

Along with first production at Germain, we anticipate regulatory approval for our proposed cumulative 150,000 barrel-per-day expansion through Phase 2, 3 and 4 later in 2013. We also anticipate that other regional operators in the Grand Rapids will advance their projects, setting the stage for the Grand Rapids to be widely recognized as one of the province’s major clastic bitumen plays. Five regional operators are advancing projects in the Grand Rapids, attracted by the formation’s geological consistency and continuity, and the opportunity. because of the Grand Rapids’ lower geological risk and lateral continuity, operators are able to use considerably longer well bores. Piloting of 1,200-m laterals, 50 percent longer than a standard horizontal well-pair in the Grand Rapids, is underway by one operator, creating potential for the Grand Rapids to achieve upper-quartile SAGD rates.

Future synergies between Germain and Saleski include levering the scale of the neighbouring projects and coordinating infrastructure and shared services such as operations and marketing. We also foresee increased efficiency in combined operations staffing and spreading fixed costs across both projects, which is expected to provide Laricina with a competitive advantage over stand-alone projects.

InnovationA fundamental principle at Laricina is to identify, develop, and apply innovation and technology to improve the in situ recovery process. Commercial production at our projects does not depend on future commercialization of technology. Rather, the role of technology is to enhance the value of our projects. It is not about getting at the assets, it is about getting more from the assets.

Our innovation record began with asset prospecting and capture in the Grosmont and Grand Rapids. It has continued in repeated cycles of learning and adaptation, and can be seen in every part of our business, particularly our approach to drilling and completions, where we have made significant strides in efficiency and cost reductions. With each well, we seek improvements over the last.

beyond drilling, our focus on innovation can be seen in how we understand a reservoir using our proprietary, in-house engineering modelling software, known as the Open-Access Simulation Integrated System (OASIS). It can be seen in how we are looking at the delivery of energy, with our work in moving away from conventional steam application to the use of radio frequency heating and solvents, particularly how we seek to enhance the efficiency of that energy, with PHARM and SC-SAGD.

A FunDAMEnTAL PRInCIPLE AT LARICInA

IS TO IDEnTIFy, DEVELOP, AnD APPLy

InnOVATIOn AnD TECHnOLOGy. IT IS AbOuT

GETTInG MORE FROM THE ASSETS.


TeamThe energy sector is a business of competitive advantage, where ideas are created and acted upon. We are fortunate that experienced professionals, field operators and new graduates have chosen to work at Laricina. The attraction of Laricina is our commitment to act on ideas, develop and steer them, to add economic efficiencies to our assets.

We continue to build our team. At the executive level, 2012 additions included Dean Setoguchi, Senior Vice President and Chief Financial Officer; David Safari, Vice President Facilities; and in 2013, James Hand, Senior Vice President Operations and Chief Operating Officer. In the field we added 12 personnel to support the Germain start-up, and in the Calgary corporate office we have grown to 116 staff. And as always, we continued an active student program, with 21 students in 2012.

Environment, Health and SafetyLaricina’s safety performance and environmental impact successes are based on operational integrity. Operational integrity means avoiding shortcuts and ensuring that process safety and the protection of our workers, other stakeholders and the environment are priorities. Much like our approach to innovation, we learn and improve as we go along. Failure in safety is often a failure to learn or modify an item, process or procedure. Learning from what we do enhances operational integrity. Laricina’s 2012 environmental, health and safety performance was excellent: zero lost-time injuries, a decrease in our total recordable injury frequency, and no material environmental or regulatory compliance issues.

Community RelationsOur approach to community engagement is based on mutual respect. Respect means that we strive to understand our impacts on the community and take an active role as a community participant. The community in which we operate understands our commitments and contributions. This mutual understanding forms the basis for a sustained relationship which, over time, develops into an effective partnership.

We have engaged community-based businesses with right-sized contracts, where the scale enables local business to participate, succeed and develop into a competitive supplier. Laricina’s business development contracts in our operating area totalled $8 million in 2012. Laricina also supports the local community’s review of regulatory applications.

The Company’s contributions in 2012 to social agencies focused on education, health, recreation and culture. They included research and scholarship support at the university level, plus donations and employee matching to social agencies in Calgary and Wabasca, the main community in our operating area.

CapitalHow and when Laricina raises capital reflects our approach to managing growth, and our focus on private equity thus far has been strategic and has resulted in high-quality investors who appreciate the strength of our assets and team. Respect for our investors and their objectives, and our commitment to steward each dollar raised, has influenced our approach to financing. Each equity issuance has provided funds to advance our projects, and each advancement increases project clarity, certainty and value.

LARICInA’S SAFETy PERFORMAnCE AnD

EnVIROnMEnTAL IMPACT SuCCESSES ARE bASED On

OPERATIOnAL InTEGRITy, PROCESS SAFETy AnD THE

PROTECTIOn OF OuR WORkERS, OTHER InDIVIDuALS

AnD THE EnVIROnMEnT.


Going forward, in addition to private equity, we are considering debt, joint ventures, and under favourable market conditions an initial public offering (IPO) as possible sources of capital. Having advanced our operations to the commercial stage, having demonstrated our ability to execute projects at Saleski and Germain, and nearing the completion of infrastructure, we are well-positioned for other sources of financing.

Our growth as a company makes public markets an option and a potential IPO will be determined by the broader economic environment as we continue to achieve operational milestones. We will continue to evaluate our financing options and will select what we see as the best combination given our progress and the economic environment.

Following capital spending of $261 million in 2012, we began the year with almost $346 million in working capital and no debt. With capital expenditures of more than $500 million expected over 2013-2014 to advance future expansions, additional capital will be required. Regardless of private or public equity, debt or joint venture funding, our main financing principle will continue – to partner with high-quality capital.

Commodity Market ConditionsTwo-thousand twelve was more uncertain for the oil sands industry than prior years with differentials dampening prices for Canadian oil, poor public equity market performance and international political and monetary uncertainty.

Market access for Canadian crude oil remains a critical factor. Advancing domestic export pipeline options to Canada’s west and east coasts and into the united

States is the critical near-term issue. Expanded export transportation to markets in the united States, eastern Canada and the Pacific Rim would greatly reduce or even collapse the large regional differential in oil pricing.

There has been a great deal of discussion around exporting crude oil by rail. We see rail playing a complementary role in some areas, and indeed Laricina is transporting some Saleski pilot volumes via rail as we seek to test all transportation options. Rail can help producers to reduce the price differential currently depressing intra-Alberta oil prices by adding incremental export capacity. It also provides the potential to source and backhaul diluent from refining and natural gas liquids processing regions at a transportation-adjusted discount to the current premium prices at Edmonton. but given its cost and complexity, rail is ultimately a marginal transportation mode. For projects with large scale and long reserve life, pipelines are the most cost-effective and safest way to move crude oil. That is why the Stony Mountain Pipeline is a strategic asset for Laricina.

Oil export capacity is a key concern to the Alberta and federal governments. both recognize that the energy sector is our country’s largest economic driver and wish to avoid reductions in capital investment and missed opportunity for public revenues. We are grateful for the policy stances of both governments and their active support for responsible crude oil export solutions.

OutlookThe advancements of 2012 set the stage for our operational goals in 2013. Achieving key operational milestones, receiving regulatory approvals for expansions, securing ongoing financing for our future projects, and the impact of the political and economic environments, will dictate Laricina’s pace of growth in 2013. The Germain

In ADDITIOn TO PRIVATE EquITy, WE ARE

COnSIDERInG DEbT, JOInT VEnTuRES, AnD

THE EVER-ELuSIVE InITIAL PubLIC OFFERInG

AS POSSIbLE SOuRCES OF CAPITAL.


and Saleski projects, where we have infrastructure coming into place, scale firmly established and design optimization being demonstrated, will remain our primary focus as we drive towards our net installed production capacity milestone of 42,500 barrels per day in 2016. We will also continue to advance our understanding of two other project areas with winter seismic programs at burnt Lakes and Conn Creek, and the pursuit of innovations that enhance asset value will remain a high priority as we look towards our longer term goal of net installed production capacity of 100,000 barrels per day in 2020.

Laricina’s activities in 2013 are focused on advancing our two current projects.

Operations:• DelivertheGermainCDPonscheduleandbudget

and achieve first production. Applying what we have learned through experience at the Germain CDP towards cost containment and improvements for Germain Phase 2;

• AdvanceSaleskiPhase1withcontinuedengineering,procurement, and drilling; and

• EnhanceSaleskipilotperformance,includingdemonstrated repeatability of the C-SAGD process, growing production, evaluating solvent performance through further testing cycles, and determining the extent of communication between the C and D zones in the Grosmont Formation.

Regulatory:• ReceiveanticipatedregulatoryapprovalsforSaleski

Phase 1, Germain Phase 2, and the Stony Mountain Pipeline.

Capital:• Thedecisiononhowbesttostructureourfinancial

needs will be positioned by our performance, achieving key milestones throughout the year, and of course, the impact of general economic conditions outside our control.

Germain and Saleski are Laricina’s current projects. Combined, they have more than 500,000 barrels per day in gross production potential, and by 2020 we will be only 20 percent of the way there based on our current plans. Our years of cumulative knowledge and experience, combined with established infrastructure, will mean that the highest returns on new capital will very likely be from these two assets.

Laricina has other prospects as well. The Winterburn carbonates at Germain will be developed based on what we learn at Saleski in the Grosmont. The burnt Lakes carbonate prospects and other growth properties like Poplar and Conn Creek provide optionality, including monetization opportunities. Each step we take at Saleski and Germain advances our longer-term goals, building on what we already have achieved and what we have learned.

Two-thousand thirteen promises to be another exciting year for Laricina and, notwithstanding the expected challenges, I look forward to charting our progress as we make our next big steps.

Glen C. Schmidt President, Chief Executive Officer and Director April 4, 2013

COMbInED, GERMAIn AnD SALESkI HAVE MORE

THAn 500,000 bARRELS PER DAy In GROSS

PRODuCTIOn POTEnTIAL, AnD by 2020 WE WILL

bE OnLy 20 PERCEnT OF THE WAy THERE.

(signed)


We ProduceBItumen from the

Grosmont at saleskISaleski pilot plant

oPerATionS revieW

From left to right: Martin Belanger, Director, Production Operations; Christina Bell, Senior Geological Technologist; Steven Brand, Team Lead, Saleski Pilot

Our teams have continued to respond and understand the challenge of the Grosmont reservoir, where we are now leading the commercialization of this huge carbonate resource.”– Steven Brand, Team Lead,

Saleski Pilot

(1) GLJ Report effective December 31, 2012. See Reserves and Resources starting on page 41 and the Glossary and Abbreviations on the inside back cover.


Since initiating production from the Grosmont in 2011, Laricina’s central objective at Saleski during 2012 was to demonstrate that the reservoir was commercial, meaning it could achieve sustained production rates so that, if replicated over many wells, a scaled-up project would be economic. In other words, the goal was to see how Saleski could make money.

Laricina succeeded in demonstrating commerciality in the Grosmont in 2012. This is a major milestone in de-risking not only the Saleski project, but the wider Grosmont Formation. With over 400 billion barrels of bitumen in place according to the Alberta Energy Resources Conservation board (ERCb), widespread commercialization of this reservoir could provide significant long-term benefits to Alberta’s economy.

Two adaptations in particular were key to achieving commercial production rates. First, we developed and implemented near-balanced drilling (with reservoir pressure matching drilling fluid pressure) to reduce

cuttings induced well bore damage. We also completed the wells open-hole (no liner). The early wells we drilled were over-balanced (with fluid pressure exceeding reservoir pressure) and completed with a slotted liner, and we found that near well bore cuttings damaged the formation and affected the production performance of these wells. The revised approach has delivered much-improved production performance.

Our second adaptation was to modify the bitumen recovery method to C-SAGD, in order to maximize the effects of steam in the reservoir (see sidebar on next page for definition of C-SAGD). The change to C-SAGD ensured that the injected steam was effectively heating the rock and oil while alternating injection and production. The benefit of high permeability in the Grosmont Formation means that high-pressure steam above the fracture pressure is not required to force heat into the reservoir during injection. During production, gravity does its job of delivering the mobilized oil through the formation fracture system to the horizontal well.

2012: AdvAncing The SAleSki PiloT

1.6 million net bbls best estimate

contingent resources (1)

282,500 bbls/d gross

production potential (1)

76 million net bbls

probable reserves (1)

60% working interest in 42,880 acres

64delineation

wells

197km

2-D seismic

2.3square-km 4-D seismic

42square-km 3-D seismic

application update filed for phase 1

commercial project of

10,700 gross bbls/d

SAGDproductionfrom1D

march 2011

FirstC-SAGDproductionfrom1C

Drillingcommenceson2C

December 2011

Both1Cand1Doncyclicproduction

march-april 2012

Solventinjectionwithsteamtestedon1C

september 2012

Firstproductionfrom2C

June 2012

FirstshipmentofdilbitleavesSaleskiPilot

may 2011

Dec. 2010-Jan. 2011SAGDwarm-up

on1Cand1Dwell-pairs

sept.-nov. 2011Stimulationson1Cand1Dwells

april 2011SAGDproduction

from1C

may 2012Commencefirstcyclicsteaminjectionon2C

January 2012Commissionedsecondonce-throughsteam

generatorincreasingthepilot’ssteamcapacity

august 2012Beginsecondproduction

cycleon2C

N


oPerATionS revieW

cyclic steam-assisted gravity drainage is an in situ

process used to recover bitumen from the grosmont

carbonates. it involves alternating cycles of steam

injection and bitumen production from a single

horizontal well.

The pilot was modified to C-SAGD and four of the eight wells were converted. Although the pilot was not designed for C-SAGD, the conversion did not require major modification of the well pad or central processing facility (CPF).

Cyclic steaming of our first well in the C zone of the Grosmont Formation (1C) began in December 2011. The well achieved a peak rate of 800 barrels per day in each of its first two production cycles, delivering Laricina’s sought-after breakthrough in this carbonate reservoir. Steaming of the second C zone well (2C) began in May 2012. This second well was drilled using the near-balanced technique, completed open hole without a slotted liner, and stimulated prior to starting operation. The production response was tremendous, climbing to a daily peak rate of more than 1,200 barrels per day within one week, from a horizontal leg of only 450 m (typical SAGD wells have horizontal legs of 800-1,200 m). The 2C well is the basis for Laricina’s Phase 1 commercial development at Saleski.

The Grosmont’s higher and thicker D zone was also tested under C-SAGD. The first D zone producing well achieved a peak daily rate of approximately 600 barrels in August 2012. Although our priority at the pilot has been the C zone, the production experience from the D zone was very encouraging through 2012. Laricina expects its understanding of this zone to progress further through 2013.

During the 1C well’s fourth cycle in September 2012, Laricina initiated testing solvent injection into the Grosmont. The well was switched to production in late

September and Laricina monitored the bitumen production rates and solvent return over the following months. The recovery process remains at an early stage, but initial results include a peak bitumen rate higher than in the previous cycle and production occurring at a lower temperature than under steam alone. The addition of solvents to the C-SAGD process is an important long-term goal to improve economics and environmental benefits by reducing heat and energy inputs, thereby lowering the SOR and improving recovery at Saleski and Germain.

by year-end, the Saleski pilot had delivered cumulative bitumen production of 186,000 gross barrels. In December 2012 the pilot averaged 915 gross barrels per day, its best monthly performance to that date. Going into 2013, the wells have continued to perform as expected and are producing through longer cycles.

2DGrosmont D

Grosmont C

Marl

1D

1C2C

Producing well Suspended well

Caprock

26m

1m

18m

WEll PlaCEMENT IN THE GROSMONT aT SalESKI

C-SaGD


SAleSki: WhAT We deMonSTrATed in 2012• Commercial steam injection and bitumen production

rates have been achieved from the Grosmont carbonate formation;

• Wehavedrilled,completed,stimulatedandproducedhorizontal wells on a sustained basis without a liner in the C zone, avoiding reservoir damage, improving injectivity and productivity and reducing costs;

• Demonstratedreservoirsteaminjectivityofgreaterthan700 m3 per day in a 450 m-long horizontal well, indicating that greater than 1,200 m3 per day should be possible in commercial-length horizontal wells;

• ProducedGrosmontbitumenhasbeentreated,blended, transported and sold to markets across north America;

• Producedwateranalyzedfromthepilotconfirmsthat the water can be treated and recycled on a commercial basis; and

• Datafrommonitoringwellsindicateslocalizedtemperature and pressure communication between the Grosmont C and D zones.

Porosity and permeability – Laricina has been keen to demonstrate that the Grosmont reservoir will yield bitumen not only from the secondary porosity such as natural fractures, but also from the primary matrix porosity of the carbonate rock itself. unloading of matrix porosity has been clearly demonstrated at Saleski. As for permeability, observed flow rates at relatively low reservoir temperature indicate good permeability for long-term production and recovery.

Communication between the Grosmont C and D zones – We have monitored and found evidence of localized heat transfer between the wells in the C and D zones, and initial evidence of pressure and fluid communication. Gathering further evidence from the 1C/1D and 2C/2D wells is a goal for 2013.

4-D seismic – The objective of time-lapse or 4-D seismic is to determine the changes occurring in the reservoir as a result of hydrocarbon production or injection of steam into the reservoir over time by comparing the repeated datasets. It provides valuable information, including confirming “well conformance”, which means that the entire well is contributing to production and the steam influence is relatively uniform and contained.

2013 Saleski Pilot ObjectivesThis year’s objectives at Saleski are to continue to prove technologies for advancing the Grosmont’s development and moving to Phase 1 commerciality. Specific goals include:

• Continuingtogrowthepilot’saveragedailybitumenproduction, to a 2013 average range of 600-800 gross barrels per day, demonstrating the ability of C-SAGD wells to deliver a sustained average rate;

• ContinuedtestingofC-SAGDrecoveryintheGrosmont D zone;

• Evaluatingsolventperformanceanddetermining next steps;

• Determiningtheextentofthermalinteractionbetweenthe Grosmont C and D zones and how we operate these zones as a system rather than individual wells; and

• Continuingtorefinethemarketingprocess,includingbitumen blending, trucking and rail transportation.

SalESKI PIlOT 4-D SEISMIC IMaGE SHOWING HEaT aFFECTED REGION

Observation wellHorizontal well

2C 1C


In October 2012 Laricina filed a regulatory application update with the ERCb and Alberta Environment and Sustainable Resource Development (AESRD) to construct Saleski’s first commercial phase. The strong performance of C-SAGD pilot wells provided the technical data to support the Saleski Phase 1 application update, which includes added steam capacity for C-SAGD operations and single horizontal wells instead of well-pairs. As before, Phase 1 will have licensed production capacity of 10,700 barrels per day. This will be the industry’s first commercial-scale bitumen project in the Grosmont carbonate. Regulatory approval for Phase 1 is anticipated in mid-2013, with drilling starting as early as October, and first steam targeted for late 2015.

An optimized well pad design, a smaller footprint for the CPF, the reduced expense of drilling single wells rather than well-pairs, along with greater project control and

detailed planning, have enabled a further reduction in the Phase 1 cost estimate from $600 million to $550 million. This yields a capital cost of approximately $51,500 per installed daily barrel of production, representing acceptable capital efficiency for a project of this scale and stage of development. Laricina is working on engineering and execution strategies, as well as phasing the initial well

SAleSki PhASe 1

oPerATionS revieW

N

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

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

N

T84

T85

R18 W4 R19

R20

N

3-D seismic area

4-D seismic area




Camp site

Borrow pit

Road

Gas pipeline


Road and pipeline

Water disposal well

Water source well



N

T84

T85

R18 W4 R19

R20

SalESKI PHaSE 1 DEvElOPMENT PlaN

N

3-D seismic area

4-D seismic area




Camp site

Borrow pit

Road

Gas pipeline


Road and pipeline

Water disposal well

Water source well



N

T84

T85

R18 W4 R19

R20

SalESKI PHaSE 1 DESIGN SuMMaRy

InstalledSOR 3.9

SteamCapacity 41,728bbls/d

BitumenCapacity 10,700bbls/d

WellDesign Upto32

TargetedFormation InitiallyGrosmontC

RecoveryMethod C-SAGD

WellSpacing ~60metres

From left to right: Darcy Riva, Manager, Saleski Assets; Wei Wei, Engineer in Training

Note: There is not necessarily a consistent level of activity throughout the range of task completion.


drilling to further reduce and manage the capital required to deliver the project. Our goal is to save another 5-10 percent of project capital costs going forward.

Phase 1 operations will include recycling water produced from the C-SAGD wells in order to reduce non-potable makeup water volume obtained from deep underground water-source wells. The Saleski pilot’s performance suggests there could be advantages in the treatment and re-use of water produced from the Grosmont carbonates, something not done with sand reservoirs. Advantages could include a reduction in treatment equipment and associated capital, along with significant environmental benefits. The facility will meet regulatory water recycle requirements.

Laricina is targeting late 2015 to initiate steam injection at Saleski Phase 1, depending on the timing of additional financing for project drilling and construction. A staggered start-up of producing wells is expected to ramp production up to the licensed bitumen output within six to 12 months of initial steam injection. This is a faster start-up than under SAGD, due to the plant’s added steam capacity and our learnings from the high initial bitumen rates from the Saleski C-SAGD wells. Initial Phase 1 development, as currently applied for, will focus on recovery from the Grosmont C zone. We expect, however, to add wells in the D zone in Phase 1 and future phases at Saleski as further understanding of the D zone is gained. Additionally, solvents are expected to be injected within two years of initial C-SAGD production.

It’s great to be a part of a team working on such a significant project. We are learning and challenging each other every day. Everyone here is committed to getting successful results.”

– Darcy Riva, Manager, Saleski Assets

SalESKI PHaSE 1 FORECaSTED TIMElINE

201320122006 to 2010

CURRENT SCHEDULE 201520142011

PublicConsultationProcess

RegulatoryReview

EngineeringandModuleFabrication

Construction

DrillingandCompletions

CommissioningandStart-up

TITlE


SAleSki long-TerM develoPMenT PlAnLaricina’s long-term plan is to develop the Saleski project over six commercial phases, achieving gross installed capacity of 282,500 barrels per day. Following the 10,700-barrel-per-day commercial Phase 1, the subsequent phase is planned to be 30,000 gross barrels per day. Phases 3 through 6 would each add approximately 60,000 barrels per day of gross bitumen production.

Capital management, cost control and efficient execution of every element will be key areas of focus throughout Saleski’s multi-phase development. Progressing the development in phases allows Laricina to manage the capital requirements and incorporate operating insights and efficiencies into the subsequent phases. Each phase will be planned with sufficient steam capacity to meet an operating SOR target of 3.0 to 3.5 under steam alone, with the goal being to operate with a considerably lower SOR following the addition of solvents.

MArkeTing And inFrASTrucTureSince 2008 Laricina has been working to plan and assemble the required road, electricity, natural gas and, most recently, takeaway pipeline infrastructure to support the Saleski and Germain projects. The past five years have seen this region transformed from a virtual frontier into a development area with nearly complete infrastructure for commercial-scale oil sands operations. This is a major step in the de-risking of Saleski and Germain.

Wherever possible, infrastructure is sized robustly to support both projects and their expansion phases.

Saleski Bitumen MarketingPilot production continues to be trucked to regional terminals. The sales price for Grosmont blended bitumen has achieved similar pricing to product from McMurray projects. Laricina dilutes Grosmont bitumen with condensate from the Edmonton area. Volumes and scheduling for early-stage marketing have been uneven as

oPerATionS revieW

SalESKI-GERMaIN INFRaSTRuCTuRE PlaTFORM

Saleski

754

913

Germain

R24R25 R23 R22 R21 R20 R19 R18 R17 R16

T86

T85

Ath

abas

ca R

iver

Wabasca-Desmarais

T84

T83

T82

T81

T80

T79

T78


Gas pipeline

ATCO 240kV powerline and substation


Highway

Road

Bridge

Plant site

Saleski

754

913

Germain

R24R25 R23 R22 R21 R20 R19 R18 R17 R16

T86

T85

Ath

abas

ca R

iver

Wabasca-Desmarais

T84

T83

T82

T81

T80

T79

T78

Proposed Stony Mountain Pipeline and terminalGas pipeline

ATCO 240kV powerline and substation

Proposed powerline and substationHighwayRoad

BridgePlant site


the few producing wells at Saleski continue testing and go through alternating cycles of steam injection and bitumen production. With limited tankage at the Saleski pilot, trucks are mobilized as necessary, taking advantage of the all-weather road from Wabasca.

Laricina commenced trial runs of rail shipments out of the Lynton rail terminal on a spot basis in the fourth quarter of 2012. The sales have demonstrated that Grosmont bitumen is not only marketable but in fact may have some advantage over rail barrels originating from the McMurray Formation, as it requires less condensate for shipment. The trials have also shown that rail shipments can receive at times pricing better than intra-Alberta barrels. Laricina will continue to experiment with rail transportation as the Company develops its long-term marketing strategy.

SAleSki inFrASTrucTure

Electricity for the pilot is produced on-site using natural gas-powered generators, and a fuel-gas line to the site was installed in 2010. Regulatory applications for power supply to Saleski Phase 1 (scaled to service Phase 2) have been filed with the Alberta utilities Commission, with approval expected in mid-2013 and construction to begin thereafter. Power is anticipated to be in-service prior to the Phase 1 start-up in late-2015.

Road SystemSaleski and Germain are serviced by 130 km of Laricina-owned all-weather access roads. Our road network now includes the first 76 km of the Chip Lake road (formerly the Al-Pac road) running north from Wabasca. After contributing to the road’s maintenance and upgrading for several years, in 2012 Laricina acquired 40 percent ownership and operatorship in this section. upgrades in 2012 included replacing five single-lane bridges with concrete-decked, two-lane, high-load-rated bridges, and widening the road itself, leading to increased safety and travelling efficiency.

Stony Mountain Pipeline As Laricina’s bitumen production is scaled up, a permanent pipeline connection to its projects becomes essential for efficient, cost-effective and safe marketing. When daily production reaches roughly 10,000 barrels, we want to be pipeline-connected. With this in mind, Laricina advanced its own initiative – the Stony Mountain Pipeline system – to coincide with its longer-term marketing needs.

The 187-km Stony Mountain Pipeline is proposed to run from Saleski in a broad u-shape to the Cheecham terminal area south of Fort McMurray. A future extension would connect Germain as well. The Stony Mountain Pipeline is the first regional pipeline initiative in the west Athabasca region, and Laricina anticipates interest from other parties. The pipeline’s key elements consist of a 200,000 barrel-per-day, 24-inch diameter blended crude bitumen line, a 70,000 barrel-per-day, 12-inch diameter diluent return line, and a tank farm approximately 2 km northeast of the Saleski pilot.

The Stony Mountain Pipeline’s regulatory application was filed with the ERCb in September 2012. While carrying out regulatory and consultation activities, and identifying areas of concern such as impacts on traditional land use and caribou habitat, Laricina advanced preliminary engineering and design work. Following further stakeholder consultation and review by the ERCb, approval is anticipated by mid-2013. Construction could begin in late 2013, subject to additional funding or other commercial arrangements, with the system’s 200,000-barrel-per-day blend line entering service in mid-to-late 2015, servicing Saleski Phase 1. Laricina’s diluent requirements will still be provided via trucking until the diluent return line goes into service roughly a year later.

Laricina is considering a range of commercial structures and financing sources to maximize the Stony Mountain Pipeline’s strategic benefits.

Germain CDP under construction


oPerATionS revieW

From left to right: Jessica Norman, Operations Analyst; David Stachniak, Team Lead, Germain; Sandeep Solanki, Director, Germain Asset and Innovation

Start-up at the Germain CDP will open up an entirely new region in Alberta for oil sands production and will begin to shift roughly 150 billion barrels of bitumen from ultimate potential to established reserves.”– Sandeep Solanki, Director, Germain Asset and Innovation

We AreBuIlDInG at GermaIn

(1) GLJ Report effective December 31, 2012. See Reserves and Resources starting on page 41 and the Glossary and Abbreviations on the inside back cover.


Progress at the Germain CDP accelerated in 2012, with construction reaching peak manpower late in the year at 208 in mid-winter 2012. The remaining four of 10 horizontal SAGD well-pairs were drilled (six drilled for start-up and four for sustaining production), and infrastructure continued to be built. Laricina exited 2012 with the project on-budget at $435 million and with first steam scheduled to commence in mid-2013 as planned. First bitumen production is expected to follow roughly three months later, and will be Laricina’s first production from the Grand Rapids sands.

2012 accomplishmentsAs of year-end 2012:

• Engineeringcomplete;

• Modulefabricationandpipingpre-fabrication98percent complete;

• 72of81modulesdeliveredtosite;

• Construction44percentcomplete;

• Completionofthefinalfourwell-pairsunderway;

• Non-potablewatersourcewellscompleted and equipped;

• WaterActapplicationandGroundWaterManagementPlan update submitted;

• 3-Dseismicbaselineacquisitionstarted;and

• Surfaceheavemonitorsinstalledandbaselinesurveyconducted.

Construction PhilosophyGermain’s development is being staged over six phases, with the CDP being Phase 1. The staged approach is being done to manage technical risk, to distribute capital requirements while achieving economies of scale, to manage the marketing of incremental production volumes and, above all, to ensure that innovations and optimization achieved in one phase are transferred to subsequent phases. Optimization areas include our well drilling and completions approach, well pad design, the use of solvents, well placement in relation to basal formation water, and the CPF’s size. Even prior to start-up, Laricina has identified improvements to well drilling and well pad design that will be applied to future phases.

Our phased approach has allowed us to take advantage of standard equipment and module sizing, which in turn expands our options for transportation and logistics. It allows us to better address any stakeholder concerns, and allows for continuous employment of a roughly equal-sized workforce. This greatly contributes to site administration and a manageable flow of work.

The CDP’s initial budget was conservative to ensure that this critical first phase went smoothly as well as pre-investing for future phases. Going forward, we feel confident we will be able to reduce costs at every opportunity. because the CPF represents the largest cost at each phase, a smaller physical footprint can lead to much lower costs. Future phases will aim for greater capital and operating efficiencies, as well as higher well productivity in a drive to maximize cash flow and net present value.

gerMAin coMMerciAl deMonSTrATion ProjecT

934 million net bbls best estimate

contingent resources – grand rapids (1)

433 million net bbls best estimate

contingent resources – Winterburn (1)

205,000 bbls/d gross production

potential – grand rapids (1)

40,000 bbls/d gross production potential – Winterburn (1)

application filed for germain phases 2-4

150,000 gross bbls/d

389 million net bbls

probable reserves (1)

100% working interest in 44,161 acres

172delineation

wells – grand rapids

90.1km

2-D seismic – Winterburn

12.8square-km 3-D seismic

– grand rapids


oPerATionS revieW

InfrastructureElectrical power and fuel gas are in place and will be commissioned in 2013. The 22-km fuel-gas line was laid in 2011 and the metering station was installed in the third quarter of 2012. utility power infrastructure was completed in 2012. This includes new ATCO substations at Livock and Germain, the Livock to Germain 144 kV transmission line and the 25 kV local distribution line from the Germain substation to the CPF. The Germain substation will service the CDP and Phase 2.

2013 CDP Start-up PlanThe planned operating staff requirement is approximately 40. After construction is complete, the construction team will hand over the facility to the operations team for plant commissioning. Commissioning will include “first fills”, priming tanks and piping to test operational readiness.

Laricina anticipates first oil in late 2013. Once production starts, the steam injection rate will be increased to promote vertical and lateral growth of the steam chamber, and our modeling shows that production should ramp-up under SAGD over the subsequent months. During the ramp-up phase Laricina will implement SC-SAGD and begin adding solvent to steam and expects production to rise another 25-30% and reach project capacity over a 12-18 month period. This should occur before year-end 2014 under our current plan.

SolventsLaricina expects to be the industry’s first operator to inject solvents into the Grand Rapids. We see great potential in supplementing the SAGD process with hydrocarbon solvents. Laricina’s full project development SOR is projected to be 2.2 with SC-SAGD.

The benefits of solvents would be substantial, including a significant down-sizing of the CPF for each phase, reducing capital needs and increasing the capital efficiency per unit of reserves and daily production. Solvents should also drive higher per-well productivity, achieving faster reservoir drainage, and increasing ultimate resource recovery.

GERMaIN PHaSE 1 (CDP) DESIGN SuMMaRy

InstalledSOR 2.1

SteamCapacity 10,500bbls/d

BitumenCapacity 5,000bbls/d

WellDesign 10well-pairs

TargetedFormation GrandRapids

RecoveryMethod SC-SAGD

WellSpacing 60metres

in the solvent-cyclic steam-assisted gravity drainage

process, steam injection is quickly followed by solvent

to further reduce bitumen viscosity. the initial solvent

is typically heavier, followed by lighter solvents in later

cycles. throughout the process, the amount of steam

utilized decreases.

SC-SaGD

Injection well Producing well

Basal Water

Bitumen Sand

17m

4m

WEll PlaCEMENT IN THE GRaND RaPIDS aT GERMaIN CDP


Other operators have reported good results from adding solvents in the McMurray oil sands, including successful well start-ups and enhanced performance. Laricina hopes to improve on the current per-well production forecast of approximately 500 barrels per day (with SAGD), to rates similar to those found in the McMurray when using solvents, which can range between 700 and 1,200 barrels per day.

Basal WaterThe majority of oil sands reservoirs have a layer of water at the bottom of the bitumen zone, known as basal water. The industry’s historical aversion to water in reservoirs has dictated placement of SAGD producing wells above the basal water. This approach has been found to reduce ultimate bitumen recovery because a portion of the bitumen mobilized drains into the basal water below the producing well. This bitumen is forever stranded. ultimate bitumen recovery is reduced and a portion of the thermal energy injected into the reservoir is wasted.

Laricina is of the view that placing the producing well in the basal water can maximize ultimate bitumen recovery. To compare performance over time and optimize placement of the well bore for future phases, six producing wells at Germain’s CDP were placed in the basal water and the other four in the bitumen zone. In both cases, the injectors are 4-6 metres above the producers, all in the bitumen zone.

What We have learnedThe CDP has already delivered critical knowledge and understanding that will be applied to reduce capital and operating costs in future phases.

Following the first six well-pairs, Laricina implemented improvements to the drilling process, wellhead design and sub-surface thermal connections, and achieved greater efficiency from a centralized drilling fluid or “mud” system. This resulted in a 20 percent cost reduction to the remaining four well-pairs, already achieving costs we had been targeting for Phase 2.

Additionally, we have identified future cost reductions by rationalizing, simplifying and down-sizing the well pad and manifold design, and automating more of the processes on the next set of well pads.

Even more important, however, is the well manifold’s smaller size, enabling the placement of all components on standard truckloads and in standard-sized shipping containers, eliminating the need for over-sized loads. This reduces shipping costs and in turn expands our choices for module fabrication beyond the Alberta market, including substantial opportunities with manufacturers in eastern Canada.

With steam generation and water handling representing approximately 60 percent of the CPF’s costs, a significant opportunity for cost reduction comes from reducing the steam requirement. Laricina’s goal to reduce the SOR to as low as 2.2 would enable a 30 percent reduction in CPF capital costs for future phases.

Slant horizontal well drilling at Germain CDP

(Illustration not to scale)

Koch Exploration Canada Muskwa

(40,000 bbls/d capacitywith start-up in 2015)

Laricina Germain(205,000 bbls/d capacity

with start-up in 2013)

Canadian Natural Resources Ltd. Wolf Lake

Producing since 2004 (~2,000 bbls/d)

Cenovus Energy Ltd. Pelican Lake

(up to 180,000 bbls/d capacity with start-up in 2017)

Cavalier Energy Inc. Hoole

(80,000 bbls/d capacitywith start-up in 2015)

BlackPearl Resources Inc.Blackrod

(up to 80,000 bbls/d capacitywith start-up in 2015)


oPerATionS revieW

GRaND RaPIDS DEvElOPMENTS

induSTry AcTiviTy AT gerMAin

Grand Rapids bitumen trend > 10 metres

McMurray bitumen trend > 10 metres

Grosmont subcrop

Nisku subcrop

Grosmont bitumen trend > 40 metres

• GrandRapidsprojectstotallingmorethan 600,000 barrels per day planned by industry operators

• Morethan400,000barrelsperdayofproductioncapacity pending regulatory approval or approved

• BlackPearlResourcesInc.hasanoperating pilot at blackrod and has applied for a project of 80,000 barrels per day production capacity with start-up in 2015

• CenovusEnergyInc.hasanoperatingpilotatPelicanLake and has applied for a project of 180,000 barrels per day production capacity with start-up in 2017

• CavalierEnergyInc.hasappliedforaprojectof 10,000 barrels per day production capacity at Hoole with start-up in 2015

• KochExplorationCanadahasappliedforaprojectof10,000 barrels per day production capacity at Muskwa with start-up in 2015

Industry activity targeting the Grand Rapids oil sands has accelerated. The Grand Rapids’ regional extent and consistency as a shoreface deposit poses lower geological risk than channel sands such as the McMurray, and allows for efficient project planning and forecasting of well performance. The Grand Rapids Formation represents a massive, unrealized oil sands resource, with an estimated 150 billion barrels of original-bitumen-in-place (according to ERCb estimates). Hundreds of well cores and logs show it to be a clean, predictable sand reservoir, with far fewer shale barriers and overall variability than the McMurray.

Note:

Information on this page is based on publicly available information, ERCB filings, company reports and Laricina estimates.


Laricina’s acquisition of the Germain leases in 2006 placed it among the pioneering wave of companies actively developing projects in the Grand Rapids. To date, Germain is the largest Grand Rapids project in terms of planned production capacity, with sufficient resource to deliver over 200,000 net barrels per day from that formation alone.

The industry’s cumulative work has moved the Grand Rapids from an exploration prospect to the reserves stage. Production is being proved and moved to commercial levels, and additional pilots and commercial project phases are in the planning stages. The Grand Rapids is clearly amenable to SAGD extraction using standard horizontal well-pairs, enabling it to be economically developed using proven technologies. Industry activity around Germain has been very useful in de-risking Laricina’s CDP.

PEER GROuP COMPaRaBlES

BlackPearlResourcesInc. CenovusEnergyLtd.

CanadianNaturalResourcesLtd. Laricina Laricina

Blackrod PelicanLake WolfLake GermainCDP GermainPhase2

Depth(m) 300 240 400 200 200

Porosity(%) 36 35 36 32 32

Permeability(D) kV=2.1,kH=3.3 kV=2.5,kH=2.9 kV=1.9,kH=2.8 kV=2.5,kH=3.5 kV=2.5,kH=3.5

Initialpressure(MPa) 2 1.2 2.2 1.4 1.4

Initialtemperature(oC) 12 11 15 10 10

APIgravity(indegrees) 9.5 8.5 9 7 7

Operatingpressure(MPa) 1.7 2.5 3.0 1.4 1.4

Saturationinoilzone(%) 60 65 75 65 68

Bitumenpay(m) 20 20 14 17 16

Bitumenpayaboveproducer(m) 13 18 11 17 16

Note: Information in this table is based on publicly available information, ERCB filings, company reports and Laricina estimates.

Note: There is not necessarily a consistent level of activity throughout the range of task completion.

Germain CDP storage tanks and water treatment facility under construction (February 2013)


gerMAin PhASeS 2-4In november 2011 Laricina submitted a regulatory application with AESRD and the ERCb for a three-phase, 150,000-barrel-per-day expansion of the Germain Grand Rapids development. Phase 2 is currently planned as a 30,000-barrel-per-day facility. We subsequently received and answered one set of supplemental information requests. Regulatory approval for Phase 2 is anticipated in mid-2013.

Phases 3 and 4 will each add capacity of 60,000 barrels per day under the current filing and will progress based on managing capital requirements and incorporating what we have learned from earlier phases.

PhASe 2 Work PlAnbefore the end of 2012, Laricina completed a detailed review of the reservoir and subsequently began work on Germain’s Phase 2 design basis memorandum (DbM). The front-end engineering and design (FEED) study is scheduled to be initiated this year, subject to additional capital availability. Once completed, drafts of the Phase 2 DbM and FEED study will be refined based on the CDP’s initial performance, and construction will follow.

Phase 2 will require an estimated 40 initial horizontal well-pairs drilled from four well pads with 10 well-pairs each. Drilling is anticipated to commence in 2014.

GERMaIN PHaSE 2 FORECaSTED TIMElINE

201420132011CURRENT SCHEDULE 201620152012

PublicConsultationProcess

RegulatoryReview

EngineeringandModuleFabrication

Construction

DrillingandCompletions

CommissioningandStart-up

2006 to 2010


T85

T84

R23 R21 W4M R22

N

EIA local study areaPhase 1 plant, well pad and existing infrastructurePhase 2 plant and well padPhase 3 plant and well padPhase 4 plant and well padCamp siteBorrow pitPipeline tankageSustaining well pad, road and pipelinePowerline and substationRoadRoad and pipelineWater disposal wellWater source well

GERMaIN DEvElOPMENT PlaN

T85

T84

R23 R21 W4M R22

N

EIA local study areaPhase 1 plant, well pad and existing infrastructurePhase 2 plant and well padPhase 3 plant and well padPhase 4 plant and well padCamp siteBorrow pitPipeline tankageSustaining well pad, road and pipelinePowerline and substationRoadRoad and pipelineWater disposal wellWater source well

Subject to regulatory approvals and financing, Phase 2 is expected to commence commissioning late in the fourth quarter of 2015, with first bitumen anticipated in 2016.

Laricina’s Phase 2 regulatory application took a comprehensive approach to cover many variations, allowing design optimization without an application amendment. The capital cost is estimated at $1.2 billion which generates a capital intensity of $40,000 per installed daily barrel of production, in line with other commercial in situ oil sands projects.

Winterburn Carbonate OpportunityPotential development of the Winterburn carbonate formation represents a future phase at Germain. The Winterburn carbonates underlie the Grand Rapids and we anticipate that it could be efficiently developed using well pads and processing facilities built for earlier Grand Rapids

phases. Reservoir engineering studies over the past year have not changed Laricina’s view of the Winterburn and our C-SAGD experience at Saleski is expected to be applicable to its development. Alberta’s Winterburn carbonates remain completely undeveloped, and we are not aware of exploration or testing by other companies.

Germain Planned MarketingInitial bitumen production from the CDP will be trucked to regional terminals. Marketing and logistics will be integrated with the Saleski marketing program to exploit synergies, and will be scaled up as expansion phases enter service. As most regional oil terminals have limited tankage, Laricina may examine opportunities to participate in a dedicated terminal with tankage to eliminate the costs of truck waiting times.

Growth properties

Core projects

Fort McMurray

Wabasca–Desmarais

Burnt Lakes

Germain

Portage Thornbury

Thornbury West

House River

BoilerRapids

ConnCreek

PoplarCreek

Saleski

Fort McMurray

Wabasca–Desmarais

Burnt Lakes

Germain

Portage Thornbury

Thornbury West

House River

BoilerRapids

ConnCreek

PoplarCreek

Saleski

FortMcMurray

PeaceRiver

RedEarth

Edmonton

Alberta

Wabasca-Desmarais

oPerATionS revieW

OTHER GROWTH PROPERTIES

(1) GLJ Report effective December 31, 2012. See Reserves and Resources on page 41.


oPerATionS revieW

Laricina’s growth properties add scope and optionality to our asset portfolio. The bitumen resource at Conn Creek and Poplar Creek consists of McMurray Formation sands, the mainstay reservoir for SAGD development. The Grosmont carbonates at burnt Lakes represent a large future growth opportunity, one whose risk profile and value will evolve as the Grosmont at Saleski continues to be established.

Investment in Laricina’s growth properties is occurring at a pace that is prudent and appropriate to the Company’s year-to-year priorities and capital availability. The primary focus continues to be internal development over the medium to longer term, with monetization a secondary option.

The 2011-2012 period was devoted to internal work including a feasibility study for advancing Conn Creek that examined delineation requirements, environmental impacts, infrastructure needs and reservoir simulation for planning future facilities. Field activity has resumed over winter 2012-2013, with $6 million budgeted for Conn Creek and $7 million for burnt Lakes seismic programs. These programs are aimed at advancing resource delineation for planning the size and scope of projects to support future regulatory applications.

Conn CreekCovering 24,320 acres at 100 percent working interest and lying just west of Fort McMurray, Conn Creek is a promising McMurray oil sands deposit with 214 million barrels of best estimate contingent resources and 65 million barrels of best estimate prospective resources(1). In August 2012 Laricina shot 22 km of 2-D seismic, tying into previous core drilling. The new survey’s technically ambitious goals were, first, to determine whether seismic could distinguish between an existing well with thick bitumen-bearing sands and a well with poor sand development and, if so, to use seismic reflection to distinguish high and low-quality reservoir in undrilled areas. This is important in the McMurray, a channel deposit sand that varies laterally.

both objectives were realized and interpretation of the new 2-D data strongly suggests extensive area on our leases with the desired reservoir qualities of thickness, continuity and low inter-bedding of mud. These positive results led to a follow-on 3-D seismic program in March 2013, covering 5.1 square-km. The 3-D seismic will provide detailed insight into the extent of high-quality channel areas, facilitating selection of future drilling locations.

We unlockGrowth opportunItIes

R11 R10W4

T89

Conn Creek lease boundary2-D seismic3-D seismicDelineation well

(1) GLJ Report effective December 31, 2012. See Reserves and Resources starting on page 41.


We have two good-sized McMurray properties in Poplar Creek and Conn Creek that provide optionality, either to add low-risk production or to monetize the assets.” – Marnie Connelly, Manager, Asset Development and Growth

Laricina continues to work with the Regional Municipality of Wood buffalo and the Government of Alberta to ensure compatibility between Laricina’s development plans and city growth. The property is situated close to existing road, electrical power and pipeline infrastructure.

Poplar CreekIn February 2012 Laricina acquired the remaining 50 percent working interest in the Poplar Creek property and now holds 5,840 acres at 100 percent working interest in a McMurray resource with 129 million barrels of best estimate contingent resources.(1) This property lies near Fort McMurray and is close to existing road, electrical power and pipeline infrastructure, with one additional bridge required for permanent access. Delineation drilling to date averages approximately four wells per section, providing good indication of the resource and how to set up the initial development area. Preparing a regulatory application will require increasing the drilling density to eight wells per section and obtaining 3-D seismic to create a detailed picture of the reservoir for optimized well placement and bitumen drainage.

Burnt lakesThis large property covers 41,548 acres at 100 percent working interest and is estimated to contain 567 million barrels of best estimate contingent resources and 73 million barrels of best estimate prospective resources(1) in the Grosmont carbonates, which could support future production of 60,000 barrels per day. Laricina’s success in moving the Grosmont to commercial production at Saleski strengthens the understanding for developing burnt Lakes.

Two 3-D seismic programs, covering 13.9 square-km in the lease’s south portion and 9.6 square-km in the northeast portion, were completed in March 2013. The 3-D seismic will be used to select future well locations at this sparsely delineated and relatively remote property, where seasonal operations require temporary work camps. Environmental and engineering studies have been completed for a key creek crossing in preparation for a 60-km road to facilitate year-round access. Future drilling will depend on capital availability.

From left to right: Marnie Connelly, Manager, Asset Development and Growth; Kent Barrett, Senior Staff Carbonate Geologist; Deepa Thomas, Director, Regulatory and Environmental Performance

CONN CREEK SEISMIC


oPerATionS revieW

From the beginning, we have regarded technical innovation as a strategic tool for enhancing the in situ recovery process and the per barrel value of the resource. While all of Laricina’s projects are viable under existing technology, we aim to increase productivity and ultimate resource recovery through development and application of new technologies.

Reducing the SOR is central to many of the Company’s innovation initiatives. Steam-related operating efficiency improvements typically also increase environmental performance by lowering energy usage per barrel of bitumen produced. Laricina’s large resource base means significant incremental value is generated for every $1 per-barrel increase in future production netback or for every million barrels of incremental recovery.

Laricina is advancing innovative designs, processes and materials in its approach to drilling and completions, bitumen production, well pad configuration and central processing facilities in a number of ways:

• Reducingdrillingtimesandavoidingformationdamage through near-balanced drilling with open-hole well completions has provided great results at Saleski, and will be applied at Phase 1;

• 3-Ddisplacementmodellingtoachieveindustry-leadingcement placement design;

• Engineeringofnext-generationcasingdesign, de-risking of foam-based cement placement through successful tests and application at Saleski;

• Constructionperformanceimprovementstudy;and

• Continuedindustrybenchmarking.

Well pad containerization – We have redesigned and filed a patent application for well pads at Germain. The redesign has led to substantial reductions in cost estimates for future well pads and will be applied at Saleski Phase 1 and future Germain phases.

Communication between zones – Initial findings at the Saleski pilot provide evidence for the conceptual validity of Laricina’s Passive Heat-Assisted Recovery Method (PHARM), which received its Canadian and united States patents in 2011. The PHARM concept is based on a well in one bitumen-bearing zone benefiting from the energy added to a neighbouring zone. This would sharply reduce or eliminate the need to inject further steam in the benefiting zone, potentially averting the need for a second injection well in that zone.

We AdvAnce in situ technoloGIes

anD InnoVatIon

Laricina’s innovative container well pad design

enables the container-sized modules to be

fabricated in a cost-competitive region, then

delivered to site as standard containers at reduced

transportation cost.


From left to right: Carolina Diaz-Goano, Advisor Enhanced Oil Recovery and In Situ; Daniel Yang, Director Reservoir Engineering; Neil Edmunds, Director Enhanced Oil Recovery Advisory

The most exciting thing about innovation at Laricina is that we test and implement new technology and ideas in our reservoirs, remembering that this is a business and our projects need to be economic.”– Daniel Yang, Director Reservoir Engineering

ESEIEH – The Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH) process aims to combine solvents with heat generated through electromagnetic waves emanating from antennae placed in horizontal wells. The ultimate goal of this experimental process is to eliminate the need for steam for in situ bitumen extraction.

Laricina is participating in a consortium to conduct a field trial as part of the ESEIEH testing program. The program’s first stage, an antenna design performance test on a bitumen ore mine face, was completed in 2011. Phase 1 testing was technically successful and generated valuable data. Phase 2 testing, which will focus on underground testing, is set to begin within the next year and will take place at an ESEIEH operating partner’s oil sands facilities.

The consortium is supported by the Climate Change and Emissions Management Corporation (CCEMC), a not-for-profit organization that supports and builds on the province’s climate change strategy to reduce emissions.

OaSIS – Laricina has developed its own engineering modelling system – the Open-Access Simulation Integrated System (OASIS) – which was put into operation during 2012. The goal is to develop a flexible, robust and accurate thermal reservoir model.

Standard commercial oil and natural gas software is typically aimed at one specific process. The power of OASIS is its applicability to multiple tasks. OASIS is a tool for rapidly building computer simulators, from spreadsheet-scale problems up to advanced thermal reservoir codes with complex physics.

Laricina anticipates that OASIS will be a useful tool in learning about radio frequency and solvent processes through sub-surface modelling, and to collect and analyze data from the Saleski pilot to fully understand the reservoir, well performance and process control.

Research partnerships – A portion of Laricina’s reservoir research has been done in university labs and the Company has a strong relationship with the university of Calgary. In addition to co-sponsoring the Industrial Research Chair in Reservoir Simulation at the university of Calgary beginning in 2011, the Company co-sponsored an additional Industrial Research Chair in Modeling Fundamentals of unconventional Resources starting in 2012.


We are proud of Laricina’s work and believe that the many benefits of our industry need to be clearly communicated.” – Yvonne Walsh, Manager Community Engagement

When engaging with its neighbours in Wabasca, Laricina strives to do so with mutual respect.

In 2012, community residents attended open houses sponsored by Laricina, traditional land users participated actively with Laricina on bigstone Cree nation (bCn)-led traditional land use assessments, community leaders attended presentations, and face-to-face meetings occurred throughout the year to ensure continuous dialogue between Laricina and the Wabasca community.

The Company’s community engagement team facilitated educational institutions, governments, local agencies and other oil sands developers in coming together to begin building a sustainable local workforce.

More than 20 local companies are contributing to Laricina’s operations. The Company has awarded approximately $8 million in contracts to businesses in 2012. During the past two years, more than 470 Wabasca-area residents worked on the Saleski and Germain projects.

After announcing the proposed Stony Mountain Pipeline project in February 2012, Laricina conducted extensive local consultation and engagement on the potential impacts with Aboriginal groups, trappers, companies and municipalities. In autumn 2012, Laricina hosted two information-sharing open houses in Wabasca and another in Lac la biche.

In May 2012 Laricina facilitated the meeting of community agencies and representatives from local businesses, industry and the municipal and provincial governments to discuss how workforce opportunities could be enhanced for local residents.

Following this event, a community-led committee was formed that includes representatives from government, local agencies, educational institutions and oil sands companies. The committee will identify innovative ways to enhance education, training and employment-related initiatives as all parties work together to create positive conditions for a sustainable workforce in the Wabasca region.

From left to right: Yvonne Walsh, Manager Community Engagement; Ariella Calin, Corporate Communications Analyst; Steve Bater, Manager, Marketing and Logistics

We engAgecommunItIes anD

operate safe proJects

oPerATionS revieW

A core goal of our operations is to protect the health and safety of our people, stakeholders, assets and environment.”– Erika Löf, Health, Safety and

Environment Coordinator

From left to right: Matt Saunders, Senior Analyst; Erika Löf, Senior Health, Safety and Environment Coordinator

Ray Yellowknee, Community Engagement Coordinator

heAlTh, SAFeTy And environMenT


Laricina strives to achieve continuous improvement in health, safety and environmental (HSE) performance. The key principle of Laricina’s HSE approach is operational integrity, in which the Company ensures that physical equipment, processes and procedures are all designed and operated to the highest standards, without shortcuts. This is complemented by a focus on learning and improvement, so that shortcomings are resolved and lessons learned are implemented.

The delivery of safe projects that manage our environmental footprint also depends on the dedication of our workers, supervisors, managers and executive team. It was through their constant efforts in 2012 that we delivered significant improvements to Laricina’s HSE system and overall performance.

In addition to tracking actual performance through what are known as “lagging” indicators, Laricina focuses on leading indicators that help to shape future performance. This enables a more proactive approach to incident prevention, advancing the promotion of an increasingly effective health, safety and environmental culture. Our field teams at Saleski and Germain worked a total of 843,698 man-hours in 2012 with zero lost-time injuries. This is a true milestone that resulted directly from actions taken to improve Laricina’s use of leading indicators.

WaBaSCa – CONNECTING WITH THE COMMuNITy

the company’s local staff, consultants and contractors are dedicated to

contributing to the quality of life in the region. in 2012, they volunteered

their time on the local gang task Force, helped the Municipal District

of opportunity #17 organize a successful Business Expo, and spoke

to students at career fairs, with a focus on staying in school and

understanding career options in the oil sands industry. in December

2012, Laricina, its contractors and contract workers all joined the local

Lions club in organizing a christmas gift toy drive that resulted in toys

being distributed to nearly 100 local families. in all, Laricina supported

approximately 30 local agencies and community events in 2012.


Each individual is vital to our overall success. Our strength is in the depth and breadth of our team.”– Ann Gosselin, Manager, Human Resources

Laricina has experienced tremendous growth since its founding in 2005. The number of personnel has increased considerably in a short time, and the need for qualified professionals continues. Entering 2013, Laricina had 38 people working in the field and 116 in the Calgary head office. Throughout 2012, Laricina continued to have an active student co-op program totalling 21 students.

We have succeeded in attracting and retaining individuals who align with our culture, enabling us to build a base of high-quality employees at a rate that keeps pace with our growing needs. All staff members are required to take initiative and are held accountable. The Company seeks to develop highly interactive and effective individuals, with emphasis on teamwork within a respectful environment. Laricina’s emphasis on innovation, which includes the support structure not merely to generate ideas but to act on them, is an enduring strength in attracting people of the highest quality.

With an eye to the Company’s long-term needs, Laricina has prolific co-op and summer student programs especially for a company of its size. We continue to build technical full-time staff from our student ranks and it works well for us having full time technical staff right out of school who already know our team and our assets.

When recruiting for a new position, Laricina considers internal permanent and contract candidates as well as external candidates. Promoting from within enables us to strengthen and expand the Company through those employees who best embody our values. This complements our approach to succession planning. We also hire locally for our field operations at Saleski and Germain, working closely with several Aboriginal communities.

Laricina believes that communication helps develop and maintain a positive, productive internal culture. The Company conducts weekly learning events, open to all employees, designed to encourage Company-wide communication. The Company also pays attention to what is important to its staff beyond the workplace. Educational bursaries for employees’ children, charitable programs to support employee objectives, and fitness facilities and programs are a few examples.

From left to right: Brendan Skingle, Co-op Student; Julia Vis, Human Resources Analyst; Ann Gosselin, Manager, Human Resources

We hAve BuilT A DeDIcateD team

oPerATionS revieW

(1) GLJ Report effective December 31, 2012. See notes on page 45.


ProspectiveResources(1)

(bestestimate)ContingentResources(1)

(bestestimate)

reserVes anDresources(1)

Laricina’s assets contain very large resource potential, including best estimate exploitable bitumen initially in-place of 12.1 net billion barrels, with 4.2 billion barrels classified as contingent resources (best estimate), 0.3 billion barrels classified as prospective resources (best estimate) and 466 million barrels of probable reserves effective December 31, 2012 based on the GLJ Report(1). Of these amounts, Saleski has 1.6 billion barrels of contingent resources (best estimate) in the Grosmont carbonates, and Germain with 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.

Reserves and Resources by Formation

ProbableReserves(1)

Clastics–GrandRapids

84%Carbonates–Grosmont

16%

Carbonates–Grosmont

24%

Clastics–GrandRapids

24%

Clastics–McMurray/Wabiskaw

14%

Clastics–McMurray/Wabiskaw

76%

Carbonates–Grosmont&Winterburn

62%


The following tables summarize certain information contained in the 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 50.

Project Summary Average Lease Area Anticipated Gross Peak Working in Acres Start-up(2) Production(2)

Project Area Formation Interest (%) (gross) (year) (bbls/d)

Saleski Grosmont 60 42,880 2010 282,500Germain GrandRapids 100 39,041 2013 205,000Germain Winterburn* 100 44,161 2022 40,000BurntLakes Grosmont 100 41,548 2019 60,000ConnCreek McMurray 100 24,320 2018 30,000PoplarCreek McMurray 100 5,840 2018 25,000OtherProperties McMurray/GrandRapids 100 62,721 undefined undefined*Note:InadditiontotheGermainlandsof39,041acreswhereLaricinaholdsGrandRapidsandWinterburnrights,Laricinaholdsanadditional5,120acresofWinterburnrightsonly.(2)Seenotespage45.

Summary of Reserves and Resource Classification (mmbbls)

RESERvES CONTINGENT RESOuRCES(3) PROSPECTIvE RESOuRCES(4)

Probable Probable + Possible Property Reserves(5) Reserves(6) Low(7) Best(8) High(9) Low(7) Best(8) High(9)

Saleski(10) 76 110 405 1,619 2,730 0 0 0GermainGrandRapids 389 468 716 934 1,105 0 0 0GermainWinterburn(10) 0 0 0 433 1,157 0 0 0BurntLakes(10) 0 0 0 567 1,344 0 73 225ConnCreek 0 0 128 214 261 27 65 159PoplarCreek 0 0 0 129 201 0 0 0OtherProperties 0 0 124 309 461 0 165 451Total(11) 466 579 1,373 4,205 7,260 27 304 835

Note:Columnsmaynotaddduetorounding.

(3)-(11)Seenotespage45.


Bitumen Reserves and Resources 10 Percent Present value of Future Net Revenue Before TaxBasedonForecastPricesandCosts($millions)

At December 31, 2012 2011 Change

ProbableReserves 543 796 (253)Probable+PossibleReserves 1,247 1,148 99LowEstimateContingentResources 1,632 1,507 125BestEstimateContingentResources 8,477 9,948 (1,471)HighEstimateContingentResources 20,923 19,401 1,522LowEstimateProspectiveResources 68 93 (25)BestEstimateProspectiveResources 123 176 (53)HighEstimateProspectiveResources 666 757 (91)

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 approximately 70 percent of Laricina’s net land base. The economic forecasts have been prepared on 100 percent of probable reserves, 93 percent of contingent resources (best estimate) and 46 percent of prospective resources (best estimate).

Laricina’s bitumen reserves are associated with the Company’s Germain Grand Rapids and Saleski assets, where Laricina has applied for regulatory approval to construct commercial bitumen recovery schemes. The Company’s probable reserves increased by 20 percent over December 31, 2011 primarily as a result of reserves assigned at Saleski. Laricina’s PV10 of its probable reserves was $543 million as at December 31, 2012, compared to $796 million as at December 31, 2011, a decrease of 32 percent and is a result primarily of a downward revision to forecast prices and change in assumptions used in the valuation.

Laricina’s contingent resources (best estimate) increased by one percent from 4,171 million barrels at December 31, 2011 to 4,205 million barrels at December 31, 2012, and the PV10 decreased by 15 percent to $8.5 billion from $9.9 billion at December 31, 2011. The net change in resource volumes is a result primarily of an increase due to additional drilling and the acquisition of the remaining working interest in certain jointly-controlled oil sands properties, offset by the reclassification of contingent resources to probable reserves at Saleski. The reduction in PV10 is primarily due to a downward revision to forecast prices and change in assumptions used in the valuation, offset by increased resource volumes.

The best and the high estimate 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, whereas the low estimate is based on SAGD. For Saleski, GLJ’s evaluation reflects the C-SAGD process in the low and best estimate contingent resource and economic assessment, whereas the high estimate is based on SAGD.


Technology Sensitivity 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 projects were 1,569 million barrels and 2,060 million barrels, respectively. The total of these volumes, 3,628 million barrels, is an incremental volume of 609 million barrels greater than the proved plus probable plus best estimate contingent resources assigned in the GLJ Report for these two properties and results in an incremental $3.3 billion PV10. This assessment is included for information purposes and should not be construed as GLJ’s independent view of the technology.

Technology Sensitivity 10 Percent Present value of Future Net Revenue Before Tax(12) BasedonForecastPricesandCosts($millions)

At December 31, 2012 2011 Change

BestEstimateTechnologySensitivity 10,995 11,965 (970)

(12)SeeNotespage45.

Growth in value and Resources Recoverable Resources (mmbbls)

Growth in value and Resources Net Present value, Before Tax, 10 Percent Discount ($ millions)

2006 2007 2008 2009 2010 2011 20120

1,000

2,000

3,000

4,000

5,000

Probable ReservesBest Estimate Contingent ResourcesBest Estimate Prospective Resources

2006 2007 2008 2009 2010 2011 20120

2,000

4,000

6,000

8,000

10,000

12,000

Probable ReservesBest Estimate Contingent Resources Best Estimate Prospective Resources


notes:

(1) based on the report of GLJ Petroleum Consultants Ltd. (GLJ) regarding Laricina’s properties effective December 31, 2012 (GLJ Report) using GLJ’s commodity price forecast as at January 1, 2013. All values shown are net to Laricina’s working interest unless otherwise indicated. Recoverable resources and production estimates for Conn Creek and Poplar Creek are based on SAGD and SC-SAGD technology; Germain Winterburn is based on CSS technology; Saleski is based on C-SAGD and SAGD technology; and burnt Lakes is based on a combination of SAGD and CSS technology; Germain Grand Rapids 2P reserves based on SAGD technology and additional volumes are based on SC-SAGD.

(2) 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.

(3) 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.

(4) 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.

(5) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

(6) 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. If probabilistic methods are used, there should be at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

(7) Low estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantity will exceed the low estimate. If probabilistic methods are used, there should be a 90 percent probability that the quantities actually recovered will equal or exceed the low estimate.

(8) 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.

(9) 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.

(10) Laricina’s resources at Saleski and burnt Lakes are contained in the Grosmont Formation, and a portion of Laricina’s resources at Germain are contained in the Winterburn Formation, each a carbonate reservoir. SAGD, C-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, C-SAGD or CSS to recover bitumen from a carbonate formation.

(11) 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.

(12) 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.


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, 2012 and 2011 was prepared as of April 4, 2013 and should be read in conjunction with the audited consolidated financial statements and accompanying notes for the years ended December 31, 2012 and December 31, 2011. The financial information presented in this MD&A was prepared in accordance with International Financial Reporting Standards (IFRS).

The information in this MD&A provides management’s analysis of the financial and operating results of Laricina and contains forward-looking statements based on estimates and assumptions that are subject to risks and uncertainties. Readers are directed to the following “Advisory on Forward-Looking Statements” which applies throughout this annual report. Actual results or events may vary materially from those anticipated.

Advisory on ForwArd-Looking stAtementsThis 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”, “potential” 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 April 4, 2013, 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 annual report include, but are not limited to: geological conditions relating to the Company’s properties; the impact of regulatory changes especially as they 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 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 forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements in this MD&A and annual report are expressly qualified by this advisory and disclaimer.


Business Overview Laricina is a privately-held in situ oil sands company targeting opportunities in the west Athabasca region of Alberta. The

Company is considered to be a development-stage company as it does not expect to achieve significant production

volumes until late 2015. Focused on two major development areas, Saleski and Germain, Laricina holds a portfolio,

independently estimated as at December 31, 2012 of 466 million barrels of probable reserves, and over 4.2 billion barrels

of contingent resources (best estimate) and 0.3 billion barrels of prospective resources (best estimate) contained in

bitumen-bearing sand and carbonate reservoirs.

HigHligHts fOr tHe Year ended decemBer 31, 2012Throughout 2012, Laricina reached significant milestones in demonstrating commercial thermal bitumen production from

the Grosmont carbonate formation at the Saleski pilot and in advancing construction at the nearby Germain commercial

demonstration project (CDP) to develop the Grand Rapids sand formation.

Production volumes at the Saleski pilot increased during 2012 due to an additional well in the Grosmont C zone,

which used improved drilling and stimulation techniques; the transition from conventional steam-assisted gravity

drainage (SAGD) to cyclic-SAGD (C-SAGD); and the commencement of solvent injection in the first C-zone well.

Achievements at the Saleski pilot included peak bitumen production volumes of more than 1,600 gross barrels

per day including more than 1,200 gross barrels from the new C-zone well; gross annual production in excess of

141,600 gross barrels of bitumen; increased duration of production cycles; and a reduction in the amount of diluent

required for blending with the produced bitumen.

Advancement of the Germain CDP included the completion of engineering, completion of 98 percent of module

fabrication, delivery and installation of 72 of the 81 planned modules to site, and overall construction progress at

44 percent. Commissioning of the facility and initial steaming of the first well-pair are expected late in the second quarter

of 2013.

In addition to the development property activities during 2012, the Company completed a $30.0 million acquisition of the

remaining working interest in certain jointly-controlled oil sands properties; acquired an equity interest in the Chip Lake

road, which is linked to the Company-owned access road to the Saleski and Germain projects; advanced the installation

and provision of infrastructure; filed a regulatory application for the Stony Mountain Pipeline; and filed a project update

covering C-SAGD for the Saleski Phase 1 expansion regulatory application.

annual financial infOrmatiOn(thousands of dollars, except per share amounts) 2012 2011 2010

Total assets 1,391,561 1,372,640 850,728

Working capital 345,808 628,121 361,751

Capital expenditures (cash) 260,520 212,389 114,873

Net operating revenue (1) 5,613 2,359 –

Finance income 7,525 6,803 2,387

Net loss (30,860) (21,659) (3,884)

Net loss per common share – basic and diluted (0.47) (0.38) (0.09)

(1) Net operating revenue is defined as bitumen blend sales less royalties.


Laricina made significant achievements throughout 2012 in its progression to being an operating company. The Company

surpassed 186,000 gross barrels of cumulative bitumen production from the Saleski pilot; demonstrated commercial

production rates from the Grosmont carbonate formation; completed detailed engineering, and advanced construction

and fabrication of the Germain 5,000-barrel-per-day CDP; and completed infrastructure projects to support commercial

development at Saleski and Germain.

Capital expenditures during 2012 were primarily for the advancement of Germain CDP construction, drilling of four

additional well-pairs to be used in the Germain CDP and infrastructure to support the Saleski and Germain projects.

Laricina is a development-stage company with revenue primarily from investment of cash in low-risk investments,

bitumen blend sales from the Saleski pilot, and rental income from third parties for the use of the Company’s camps. The

net losses in 2012 and 2011 resulted primarily from the excess of operating costs over net operating revenue associated

with pilot production, and general and administrative activities required to support the Company’s continued progress.

The increase in total assets during 2011 is due to $499.6 million of net proceeds raised through equity private placements.

Finance income increased in 2012 as a result of increased funds on deposit beginning in the second half of 2011 and a

minor increase in the average interest rate for funds on deposit during 2012. Finance income increased during 2011 as

a result of increased funds on deposit from private placements completed in the second half of 2010.

OperatiOnal results(thousands of dollars) 2012 2011

Net operating revenue 5,613 2,359

Transportation and blending expenses 3,169 1,230

Operating expenses 21,933 11,421

Net operating revenue

Laricina recorded first production volumes and bitumen blend sales from the Saleski pilot during the second quarter of

2011. Throughout 2012, the Company completed production tests, commenced solvent injection, initiated injection and

production cycles through C-SAGD, and improved its understanding of the communication between the C and D zones

in the Grosmont Formation.

(barrels) 2012 2011

Net production volumes 84,970 26,900

Net sales volumes 101,920 33,300

The increases in bitumen production and bitumen blend sales volumes during 2012 are due to the completion of

a second C-zone well, which recorded first production in June of 2012, an increase in the number of days in each

production cycle and an increase in the average production per day over 2011. Cumulative production volumes since

start-up exceeded 186,000 gross barrels of bitumen by December 31, 2012, including production exceeding 28,000

gross barrels of bitumen in December 2012. Peak production of approximately 1,600 gross barrels of bitumen per day

was achieved during 2012 which included production of more than 1,200 gross barrels of bitumen per day from the

second C zone well.


A solvent injection program was initiated in the C zone during the third quarter of 2012. Initial results indicated an increase

in bitumen production rates and production occurring at a lower temperature than with steam alone. A production test on

a Grosmont Formation D zone well was completed during the second quarter of 2012 and provided evidence of localized

heat transfer between the C and D zone wells in addition to pressure and fluid communication. During the remainder

of 2013, Laricina plans to continue to study the connectivity between the C and D zones and the potential to extract

bitumen more efficiently from the C and D zones of the Grosmont Formation through combined well operations.

Bitumen blend sales volumes have fluctuated since initial bitumen production commenced in the second quarter of

2011, which is consistent with the Company’s planned C-SAGD recovery process. Laricina expects sales and production

volumes to continue fluctuating through alternating cycles of steam injection and bitumen production.

2012 2011

Average sales price per barrel $ 56.62 $ 73.06

West Texas Intermediate (US $/barrel) $ 94.21 $ 95.12

Western Canadian Select (Cdn $/barrel) $ 73.13 $ 77.15

The increase in net operating revenue during 2012 is primarily due to higher bitumen blend sales volumes, partially

offset by a lower average realized price per barrel of bitumen blend. The average sales price in 2012 decreased by

$16.44 per barrel from 2011, due to widening price differentials resulting from pipeline capacity constraints in Canada

and the United States.

Laricina’s average sales price per barrel is net of terminal fees and other charges.

Laricina pays Crown royalties on oil sands production. The increase in royalties during 2012 is primarily the result of

increased sales volumes.

Transportation and blending expenses

Transportation and blending expenses include the cost of diluent purchased for blending with produced bitumen and the

cost of transporting bitumen blend to the sales terminals. Increases in transportation and blending costs during 2012 are

the result of increased sales volumes, partially offset by decrease in the quantity of diluent required for blending and a

decrease of $7.70 per barrel of diluent purchased.

During 2012 Laricina shipped bitumen blend volumes by rail to the Atlantic and Gulf of Mexico coasts of the United

States. The addition of rail transportation to the Company’s marketing program diversifies Laricina’s delivery options

while reducing exposure to a constrained pipeline environment.

Operating expenses

Operating expenses incurred throughout 2012 and 2011 were primarily related to production from the Saleski pilot. The

increase in 2012 over 2011 is the result of a full year of production from the Saleski pilot facility, well servicing and initial

solvent injection. Due to the experimental nature of the Saleski pilot, operating costs are expected to exceed net revenue

throughout the pilot’s life. Other operating costs increases are related to additional use of the camps by third parties and

road maintenance.


Oil sands reserves and resOurcesLaricina 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, 2012 (GLJ Report).

The Company has probable reserves of 466 million barrels and probable plus possible reserves(1)(4) of 579 million barrels,

an increase from 387 million barrels and 488 million barrels, respectively, estimated at the previous year-end. These

reserves represent a portion of the bitumen resource volumes at Germain in the Grand Rapids sands and at Saleski in

the Grosmont carbonates, where Laricina has applied for regulatory approval to construct commercial bitumen recovery

schemes. The increase in reserves is the result of the first-time classification of reserves in the Grosmont carbonates at

Saleski and is supported by the pilot results.

The GLJ Report identified best estimate contingent resources(2) of 4.2 billion barrels and prospective resources(4) of

0.3 billion barrels, unchanged from the resources reported at December 31, 2011. The current high estimate contingent

resources are 7.3 billion barrels and prospective resources are 0.8 billion barrels compared to 6.9 billion barrels and

0.8 billion barrels, respectively, reported at December 31, 2011. Recovery methods including SAGD, C-SAGD,

solvent-cyclic (SC) SAGD and cyclical steam stimulation (CSS) were used when evaluating the resource potential of

each reservoir.

Reserves (1) Contingent Resources (2)(3) Prospective Resources (4)

Probable plus(mmbbls) Probable Possible Low Best High Low Best High

Saleski 76 110 405 1,619 2,730 – – –

Germain Grand Rapids 389 468 716 934 1,105 – – –

Germain Winterburn – – – 433 1,157 – – –

Burnt Lakes – – – 567 1,344 – 73 225

Conn Creek – – 128 214 261 27 65 159

Poplar Creek – – – 129 201 – – –

Other properties – – 124 309 461 – 165 451

466 579 1,373 4,205 7,260 27 304 835

Note: Columns may not add due to rounding.

(1) 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. If probabilistic methods are used, there should be at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

(2) 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 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.

(3) Contingent resources for Conn Creek and Poplar Creek are based on SAGD and SC-SAGD technology; Saleski is based on C-SAGD and SAGD technology; Germain Winterburn is based on CSS technology; Burnt Lakes is based on a combination of SAGD and CSS technology; Germain Grand Rapids Phase 1 is based on SC-SAGD.

(4) 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 discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.


The GLJ Report included economic evaluations for Saleski, Germain Grand Rapids, Germain Winterburn, Burnt Lakes,

Conn Creek and Popular Creek which collectively represent approximately 70 percent of Laricina’s net land base.

The economic forecasts have been prepared on 100 percent of Laricina’s probable reserves, 93 percent of the best

estimate contingent resources, and 46 percent of best estimate prospective resources using GLJ’s January 1, 2013

price forecasts. The net present value of future net revenue before income tax at a 10 percent discount rate is as follows:

(millions of dollars) Low Best High

Contingent resources 1,632 8,477 20,923

Prospective resources 68 123 666

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 $0.5 billion and

$1.2 billion, respectively.

The December 31, 2012 economic evaluation represents a decrease in net present value of future net revenue from

December 31, 2011. This decrease is primarily due to a decrease in forecast prices used in the valuations and changes

in assumptions relating to the timing of certain projects.

Laricina requested that GLJ provide an economic sensitivity of the best estimate contingent resources for the

Germain Grand Rapids and Saleski Grosmont reservoirs using Laricina’s risked assessment of the SC-SAGD process.

The risked assessment of SC-SAGD adds 0.6 billion barrels of best estimate contingent resources and increases the

net present value of future net revenue before income tax at a 10 percent discount rate by $3.3 billion. The incremental

value has decreased from the 2011 economic sensitivity due to a decrease in forecast prices used in the valuations

and changes in assumptions related to the timing of certain projects. These assessments are included for information

purposes and should not be construed as GLJ’s independent view of the technology.

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

Germain, Burnt Lakes, Conn Creek and Poplar Creek. At December 31, 2012, Laricina had a total of 376 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, and

the regulatory applications, as well as fulfilling lease retention requirements.


capital investmentCapital investment includes costs related to exploration and evaluation (E&E) assets, property, plant and equipment

(PP&E), and intangible assets.

(thousands of dollars) 2012 2011

E&E assets:

Land 30,302 20,079

Exploration 11,421 16,152

Development 181,000 135,917

Other 16,439 31,880

Capitalized general and administrative expenses 16,834 15,423

255,996 219,451

PP&E:

Facilities and other equipment 30,785 15,264

Corporate 2,213 1,643

32,998 16,907

Intangible assets 13,196 9,491

Capital asset additions 302,190 245,849

Capital expenditures (not including non-cash items) 260,520 212,389

Capital asset additions during 2012 were primarily to support the advancement of the Germain CDP. Expenditures

included the final major equipment purchases, completion of engineering, 98 percent of module fabrication, delivery and

installation of approximately 90 percent of the modules to site, drilling of four additional well-pairs and completion of the

six well-pairs previously drilled at the Germain CDP.

Land

On February 15, 2012, Laricina closed a transaction to acquire the remaining working interest in certain jointly-controlled

oil sands properties for total consideration of $30.0 million consisting of 705,882 common shares at $42.50 per common

share. Land additions during 2011 included $19.8 million for 12,800 net acres of oil sands leases in the Burnt Lakes

area. At December 31, 2012, Laricina’s total land holdings were 215,708 net acres compared to 209,205 net acres at

December 31, 2011. At December 31, 2012 and December 31, 2011, oil sands rights comprised 95 percent of the total

land holdings.

Exploration

Laricina’s 2012 exploration expenditures included the acquisition of 22.0 km of 2-D seismic at Conn Creek, 17.0 km of

2-D seismic at Portage, and the completion of the 2011-2012 winter drilling program of five exploration wells, of which

three were at Germain and two were at Saleski. The decrease in exploration costs from 2011 was due to a reduced

drilling program. The Company’s 2011 winter exploration program included a 15.6-square-km 3-D seismic program and

the completion of the 2010-2011 winter drilling program of 13 exploration wells.


Preparations for the 2012-2013 winter exploration drilling program consisting of three wells at Saleski commenced late

in 2012. At the date of this report, the exploration wells were completed along with 23.5 square-km of 3-D seismic at

Burnt Lakes, 14.0 km of 2-D seismic at Portage, 5.1 square-km of 3-D seismic at Conn Creek and 1.1 square-km of 4-D

seismic at Saleski.

Development activities

Consistent with 2011 the majority of development expenditures during 2012 were to support the advancement of the

Germain CDP.


Saleski 26,011 11,549

Germain 152,253 138,397

Other 33,521 1,235

211,785 151,181

During 2012, development activities primarily related to the Germain CDP included the completion of engineering,

equipment purchases, 98 percent of module fabrication, and the delivery and construction of approximately 90 percent

of facility modules. Development activities at the Saleski pilot included the construction and commissioning of a second

steam generator. Development drilling activities included the completion of six well-pairs and the drilling of four additional

well-pairs at Germain; the drilling and completion of two additional C zone wells at Saleski; and the 2011-2012 winter

development drilling program which included four observation wells to be used in future development programs at

Saleski and Germain.

Other development activities during 2012 included the acquisition of an interest in the first 76 km of the Chip Lake road

which runs north from Wabasca and connects to Laricina’s road system at Germain. Additional expenditures include

upgrades to the Chip Lake road and bridges.

Development activities during 2011 included the acquisition of equipment, advancement of engineering, site preparation

and commencement of module fabrication for the Germain CDP; a finance lease for the Germain permanent camp;

progress on construction of a fuel gas pipeline and power substation; and the commissioning of a second steam

generator at the Saleski pilot. The development drilling activities during 2011 were primarily focused on the Germain

CDP and included initial drilling of six well-pairs, 17 observation wells, eight water source and monitoring wells, and two

water disposal wells.

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, 2012,

$8.2 million gross ($4.9 million net) of this funding had been recorded as a reduction of costs associated with the Saleski

pilot compared to $5.5 million gross ($3.3 million net) at December 31, 2011.


Other

Other capital activities in 2012 focused primarily on the expansion of infrastructure required for commercial

development at Saleski and Germain. During the fourth quarter of 2012, Laricina filed a project update to the

regulatory application for the Saleski Phase 1 expansion which included additional steam capacity, single horizontal

wells and the use of C-SAGD. Regulatory and consultation work for the Stony Mountain Pipeline continued throughout

2012 including filing the regulatory application during the third quarter and commencing initial engineering. The

Stony Mountain Pipeline is a bitumen transportation system which will connect the Company’s commercial projects to

the Cheecham terminal south of Fort McMurray and includes a 200,000 barrel-per-day 24-inch diameter bitumen blend

line and a 70,000 barrel-per-day, 12-inch diameter diluent return line.

During 2011 other capital activities included pre-operating activities associated with initial steaming and first production

at the Saleski pilot, advancing the regulatory application for Saleski Phase 1, initial engineering and regulatory work for

the Stony Mountain Pipeline, and completion of the environmental impact assessment and regulatory application for the

three-phase, 150,000-barrel-per-day Germain expansion.

Throughout 2012 and 2011 other capital investment costs were incurred to advance innovation and technology projects,

such as the Enhanced Solvent Extraction Incorporating Electromagnetic Heating project, OASIS software design and

reservoir studies. The Company also made provisions for future site restoration costs and capitalized costs associated

with pre-operating activities.

Intangible assets

As at December 31, 2012 intangible assets of $12.5 million had been recorded relating to the expansion of available

power for the Company’s future development projects at Germain. The depreciation of certain components of the

pilot, such as the development wells, that contribute directly to the Company’s understanding of the reservoir and

assist in the future assignment of proved reserves are recapitalized until the related reserves are recognized. As at

December 31, 2012, $10.2 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 $243.3 million for 2013.

Of this amount, $157.1 million relates to the construction and commissioning of the Germain CDP and advancing the

Germain Phase 2 regulatory application; $15.8 million to the Saleski pilot; $13.7 million to long-lead equipment and

engineering, and development drilling for the Saleski Phase 1 expansion; $15.6 million to developing infrastructure for

Germain and Saleski; $16.5 million to conclude the 2012-2013 winter exploration drilling and geophysical program; and

the remainder to studies and corporate development. Of the total planned expenditures, $76.2 million has been carried

over from 2012 due to a timing delay of incurred costs. Laricina plans to finance future activities with current cash

resources, debt and additional private or, potentially, public equity financings.


cOrpOrate results(thousands of dollars) 2012 2011

General and administrative expenses, net 26,000 17,157

Finance income 7,525 6,803

Other income 8,516 2,892

Net loss (30,860) (21,659)

General and administrative expenses

General and administrative expenses increased in 2012 over 2011 primarily due to the continued growth in the Company’s

employee and consulting base and the additional overhead costs associated with increased personnel.


General and administrative expenses, gross 35,263 23,810

Share-based compensation costs 7,571 8,770

Capitalized costs (16,834) (15,423)

General and administrative expenses, net 26,000 17,157

At December 31, 2012, the Company had 154 employees of which 116 were based in the Calgary head office, compared

to 121 and 95, respectively, at December 31, 2011. The growth in personnel is a result of the additional expertise and

skills required to operate the Saleski pilot, construction of the Germain CDP, advancement of Saleski Phase 1 and

other infrastructure projects to support future development. Laricina expects that general and administrative costs will

increase in 2013 as the employee and consultant base increases to support operations at the Germain CDP. Capitalized

general and administrative costs consist of costs directly related to project exploration and development activities.

As the projects continue to progress towards commercialization, a smaller percentage of general and administrative

expenses will be capitalized.

During 2012, David Theriault, Senior Vice President In Situ and Exploration, announced his retirement. Dean Setoguchi

joined the Company as Senior Vice President and Chief Financial Officer and David Safari joined the Company as

Vice President Facilities. Subsequent to December 31, 2012, James Hand joined Laricina as Senior Vice President

Operations and Chief Operating Officer.

Finance and other income

The increase in finance income during 2012 is primarily due to the increase in average funds on deposit, resulting from

the net proceeds from the equity private placements completed during the second half of 2011.

Other income includes the sale of Saleski pilot data to a third party and fees charged to third parties for the usage of

Laricina’s camp facilities and roads. Net proceeds from data sales were $1.2 million in 2012 and $2.7 million in 2011.

Camp and road usage fees increased to $7.3 million during 2012 from $0.3 million during 2011.

Finance costs

Finance costs include the accretion of site restoration provisions and interest recorded on the finance lease associated

with the Germain permanent camp. Finance costs decreased by $0.3 million during 2012 from $1.4 million in 2011 due

to a reduction in finance lease obligations.


Pre-exploration costs

Pre-exploration activities of $1.0 million during 2012 included a variety of studies for purposes of improved drilling,

construction and fabrication techniques and a possible central camp site proposal. During 2011, pre-exploration

activities of $0.4 million included studies related primarily to the initial surveying work to support pipeline infrastructure.

Depreciation and amortization

Depreciation and amortization expense of $8.0 million during 2012 increased from $5.8 million during 2011. The increase

is related to a full year of depreciation for the Saleski pilot facility; in 2011 depreciation commenced in the second

quarter. During the fourth quarter of 2012, the Company began amortizing intangible assets related to the expansion of

available power at Germain.

Net loss

Laricina recorded a net loss of $30.9 million for 2012 compared to a net loss of $21.7 million for 2011. The increase

is primarily due to a full year of Saleski pilot operations and increased general and administrative expenses. Typical

of a company in early stages of operations, Laricina expects to continue to show net losses at least until commercial

production levels 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) Q4 2012 Q3 2012 Q2 2012 Q1 2012 Q4 2011 Q3 2011 Q2 2011 Q1 2011

Working capital 345,808 442,272 504,230 554,313 628,121 706,696 631,215 294,200

Capital asset additions 89,983 58,505 53,279 100,423 77,431 61,333 25,382 81,703

Net operating revenue 2,092 1,885 945 691 1,328 784 247 –

Finance and other income 2,154 4,086 4,599 5,202 4,919 2,622 1,220 934

Net loss (8,600) (7,341) (8,588) (6,331) (5,476) (6,089) (5,755) (4,339)

Net loss per common share, basic and diluted $ (0.13) $ (0.11) $ (0.13) $ (0.10) $ (0.09) $ (0.10) $ (0.11) $ (0.08)

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.

Capital asset additions in the fourth quarter of 2012 included an acquisition of an interest in the Chip Lake road

and additions in the first quarter of 2012 included a $30.0 million acquisition of the remaining working interests in

jointly-controlled oil sands assets. Fluctuations in capital additions are the result of the Saleski pilot completion and

related pre-operational activities in the first quarter of 2011; the winter drilling programs, which typically occur in the

first quarter of each year; and the progress of the Germain CDP detailed engineering, fabrication and construction

during 2012.

Net operating revenue increased throughout 2012 as a result of increases in sales volumes, partially offset by declines

in the average realized bitumen blend price. Sales volumes have fluctuated since initial production commenced in the

second quarter of 2011, consistent with the Company’s planned production cycles. Laricina expects that sales volumes

will continue fluctuating due to planned cycles of alternating steam injection and bitumen production.


Other income during 2012 is related to third-party usage of Laricina’s camps and roads. Other income in the third quarter

of 2012 and fourth quarter of 2011 resulted from the sale of certain Saleski pilot data to a third party resulting in net

proceeds of $1.2 million and $2.7 million, respectively. Finance income has decreased since the third quarter of 2011

due to decreased funds on deposit.

liquiditY and financial resOurcesWorking capital

Working capital decreased by $282.3 million from December 31, 2011 to $345.8 million at December 31, 2012 primarily

due to capital expenditures incurred, including engineering, construction and fabrication costs for the Germain CDP and

the 2011-2012 winter drilling program.

(thousands of dollars)

Working capital, December 31, 2011 628,121

Capital expenditures (cash) (260,520)

Operating activities (26,464)

Proceeds from the issuance of common shares 12,224

Other (7,553)

Working capital, December 31, 2012 345,808

Laricina has sufficient working capital to fund the completion and commissioning of the Germain CDP. The 2013

capital and operating spending program of approximately $298.7 million is focused primarily on the completion and

commissioning of the Germain CDP, infrastructure development and the advancement of the Saleski Phase 1 project.

Approximately 50 percent of the program is directly associated with the Germain CDP and five percent is tied to the

advancement of the Saleski Phase 1 project. The balance of the spending will include operations at the Saleski pilot and

Germain CDP, the advancement of future phases at Saleski and Germain, infrastructure, studies, other corporate capital,

and general and administrative expenses.

The future capital expenditures Laricina will require 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 bearing 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 1.3 percent 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, 2013 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, 2012 and the

date of this report, the Company had letters of credit totalling $3.0 million under this credit facility, and no amount has

been drawn. The letters of credit are 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.

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 of dollars) Office Field

2013 remainder 2,397 8,651

2014 2,928 6,503

2015 2,423 2,930

2016 120 1,815

2017 and thereafter 230 1,058

The Company’s letters of credit at December 31, 2012 are to suppliers of utilities to support development at

Saleski and Germain. If project development is interrupted, the Company will be required to reimburse up to $3.0

million of the suppliers’ costs. The letters of credit of $2.8 million and $0.2 million are renewable on July 31, 2013 and

August 31, 2013, respectively.

As at April 4, 2013, the Company has $28.6 million of purchase commitments which relate to the Germain CDP and

acquisition of long-lead equipment for Saleski Phase 1.

Outstanding share data

At March 31, 2013 share capital consisted of the following:

(thousands)

Common shares 67,115

Stock options 1,946

Replacement options 2,438

Performance share units 785

Total 72,284

Each stock option, replacement option and performance share unit requires the Company upon exercise and payment

of the consideration to issue one common share.


critical accOunting estimatesIFRS requires certain estimates and assumptions in the preparation of financial statements that are based on

management’s best estimates. 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 estimation of 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 provision

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 cash flows required for an asset’s future abandonment.

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.


cHanges in accOunting pOliciesA number of new accounting standards, and amendments to standards and interpretations, were not effective for

the period ended December 31, 2012 and therefore were not applied in preparing the audited consolidated financial

statements for the year ended December 31, 2012.

The Company has reviewed the new standards and interpretations required for annual periods beginning

January 1, 2013 and determined that IFRS 7 Financial Instruments: Disclosures, IFRS 10 Consolidated Financial

Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosure of Interests in Other Entities and IFRS 13 Fair Value

Measurement are relevant but not yet applicable to these financial statements. The impact of these standards has not

yet been determined.

The Company has also reviewed the new standards and interpretations required for annual periods beginning

January 1, 2014 and determined that International Accounting Standard 32 Financial Instruments: Presentation is relevant

but not yet applicable to these financial statements. The impact of this standard is not yet determined.

Further, the Company has reviewed the new standards and interpretations required for annual periods beginning

January 1, 2015 and determined that IFRS 9 Financial Instruments is relevant but not yet applicable to these financial

statements. The impact of this standard is not yet determined.

risk managementLaricina’s operational 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, planned for development or under

construction. Accordingly, the Company’s success depends on the successful execution of its construction activities,

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 currently

estimated 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 probability 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 probable or possible reserves and resources have not yet produced commercial quantities of bitumen.


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, 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,

could impact the timing and risks of regulatory approvals.

In November 2012, the Alberta government passed the Responsible Energy Development Act (REDA) in response to

recommendations made to the Minister of Energy by the Regulatory Enhancement Project (REP) team. The REP team’s

goal was 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 REP team’s

recommendation was to adopt a coordinated policy framework and an integrated regulatory system for the upstream

oil and natural gas sector. The REDA establishes the new Alberta Energy Regulator, which will assume the regulatory

functions of the Energy Resources Conservation Board, Alberta Environment and Sustainable Resource Development

with oil, natural gas, oil sands and coal development and is expected to be operational by June 2013. There are no

assurances regulatory approval will be improved by this process.

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

Government of Alberta’s approach to managing land and natural resources to meet long-term economic, environmental

and social goals. The ALSA considers the amendment or removal of previously issued items including regulatory

permits, licenses, approvals or authorizations in order to achieve an objective or policy resulting from the implementation

of a regional plan. The Government of Alberta’s first of seven regional plans is the Lower Athabasca Regional Plan

(LARP) which came into effect September 1, 2012. The LARP’s intent 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 LARP and the proposed conservation areas do not directly affect any of Laricina’s current oil

sands leases. The proposed legislation’s full impact on the Company cannot be determined until the various regional

environmental management outcomes are established.


Due to the proximity of Laricina’s Conn Creek and Poplar Creek properties to the city of Fort McMurray, the Company

is working with the Regional Municipality of Wood Buffalo (RMWB) and the Government of Alberta to ensure

compatibility between Laricina’s development plans and city growth. On August 29, 2011, the Government of Alberta

signed a memorandum of understanding with the RMWB to establish an Urban Development Sub Region (UDSR). The

UDSR will be a designated area of Crown land surrounding the Fort McMurray urban service area where future urban

development will be the primary intended land use. The UDSR will facilitate land use planning, timely release of land

for urban development and efficient infrastructure planning and construction to accommodate population growth and

urban expansion.

A draft UDSR area has been identified which is the basis for stakeholder engagement. The draft boundary extends over

portions of Laricina’s Conn Creek and Poplar Creek leases. Consultation between the Company and the Government of

Alberta is ongoing. The impact of the draft UDSR is undeterminable at this time.

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.

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

air emissions 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 per year reduce their

greenhouse gas emissions intensity by 12 percent from a regulated baseline starting July 1, 2007. 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 CDP will have reporting requirements

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. Emissions intensity reduction obligations are then phased in over a

six-year period at a rate of two percent per year beginning in the fourth year of commercial operation.

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 mid-2013. 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 commenced immediately. The estimated cost of the program

is $50 million per year and will be borne by the oil sands producers. The funding requirement will be allocated among

companies according to production levels and applications under review. Laricina was required to provide funding

during 2012 and the Company expects funding requirements to 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. Other

unconventional oil developments and other energy investments compete for available capital. There can be no assurance

concerning the impact of competition on the timing, availability or price of capital. 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 additional 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. Upon one of Laricina’s bitumen recovery projects being developed and becoming

commercially operational, Laricina’s revenue and expenses will be directly affected by the applicable royalty regime. The

economic benefit of future capital expenditures 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 natural 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 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 bitumen blend, natural gas fuel pipelines and electricity transmission

systems. Delays or restrictions in necessary infrastructure may influence the timing and scale of operations and negatively

impact financial results.

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 insurance coverage 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 dollar and Canadian dollar 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 that are beyond Laricina’s control. The Company’s future financial results

depend on future demand and on the price movement of the aforementioned commodities, including any negative price

effects arising from increased bitumen supplies from competitors.

Operating costs

The cost of natural gas is a significant component of the cost 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. Any carbon-related charges imposed by government could reduce Laricina’s future earnings.


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 have 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.

2013 OutlOOk Laricina’s current working capital provides sufficient resources to complete the Germain CDP. 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 arrangements.

During 2013, the majority of capital expenditures will be to complete the Germain CDP. During the first quarter of 2013

the Company completed the remaining four well-pairs, module fabrication and delivery of modules to site. Laricina

anticipates that initial steaming at the Germain CDP will commence late in the second quarter of 2013, with initial

production expected three to four months later.

Laricina will continue to enhance production performance at the Saleski pilot by evaluating solvent injection performance,

demonstrating repetition of the C-SAGD process and optimizing well performance.


In 2013, Laricina plans to advance the Saleski Phase 1 expansion of 10,700 barrels per day, focusing on

regulatory matters, front-end engineering and design, site preparation and drilling. The regulatory application for the

Saleski Phase 1 expansion was filed in December 2010. A project update to the regulatory application was filed in

October 2012 and included additional steam capacity and a modification from well-pairs to single horizontal wells for

C-SAGD operations. The Company expects regulatory approval in mid-2013, followed by advancement of engineering

design, ordering of initial long-lead equipment and drilling expected to commence in the fourth quarter of 2013, subject

to additional financing.

Additional activities in 2013 will include regulatory work to support the Germain Phase 2 expansions and the Stony

Mountain Pipeline application.

As the Company continues to advance its projects, additional expertise will be required to commission and operate

the Germain CDP, advance the Saleski Phase 1 expansion and develop required infrastructure. This expertise will be

required for all aspects of the business and will include a combination of head office and field employees and consultants.

General and administrative expenses are expected to increase as a result of additional salaries and overhead associated

with personnel increases.

The 2012-2013 winter exploration and development drilling programs were completed in the first quarter of 2013

and consisted of 23.5 square-km of 3-D seismic at Burnt Lakes, 5.1 square-km of 3-D seismic at Conn Creek and

1.1 square-km of 4-D seismic at Saleski; three exploration wells at Saleski; and two water source wells, two monitoring

wells and two observation wells at Saleski.

The 2013 capital and net operating spending program (including cash general and administrative expenses) are expected

to be approximately $298.7 million, mostly to complete construction and commission the Germain CDP.


Independent AudItors’ report

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, 2012 and December 31, 2011, the consolidated

statements of comprehensive loss, changes in equity and cash flows for the years then ended, and notes, comprising a

summary of significant accounting policies and other explanatory information.

Management’s responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in

accordance with 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, 2012 and December 31, 2011, and its consolidated

financial performance and consolidated cash flows for the years then ended in accordance with International Financial

Reporting Standards.

(signed)

Chartered Accountants

Calgary, Canada

April 4, 2013


ConsolIdAted stAtements of fInAnCIAl posItIonAs at December 31(thousands of dollars) Note 2012 2011

Assets

Current assets Cash and cash equivalents 12 395,884 656,891

Trade and other receivables 7,923 17,892

Prepaid expenses and deposits 818 808

Inventories 5 3,355 1,740

407,980 677,331

Non-current assets Abandonment deposits 915 906

Other long-term assets 6 1,194 1,194

Exploration and evaluation assets 7 874,354 638,405

Property, plant and equipment 8 84,587 45,313

Intangible assets 9 22,531 9,491

983,581 695,309

Total assets 1,391,561 1,372,640

Liabilities and shareholders’ equity Current liabilities

Trade and other payables 54,531 44,210

Finance lease obligation 8 7,641 5,000

62,172 49,210

Non-current liabilities Site restoration provision 10 18,982 16,178

Finance lease obligation 8 – 7,851

Deferred income tax 11 1,710 10,403

20,692 34,432

Total liabilities 82,864 83,642

Shareholders’ equity

Share capital 13 1,333,979 1,286,352

Contributed surplus 31,410 28,478

Deficit (56,692) (25,832)

Total shareholders’ equity 1,308,697 1,288,998

Total liabilities and shareholders’ equity 1,391,561 1,372,640

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

On behalf of the Board:

Brian K. Lemke Glen C. SchmidtDirector Director

(signed) (signed)


ConsolIdAted stAtements of ComprehensIve loss

For the years ended December 31 (thousands of dollars) Note 2012 2011

Revenue

Bitumen blend sales 5,771 2,433

Royalties (158) (74)

Net operating revenue 5,613 2,359

Other income 15 8,516 2,892

14,129 5,251

Expenses

Transportation and blending 3,169 1,230

Operating 21,933 11,421

Pre-exploration 1,034 364

General and administrative 16 26,000 17,157

Depreciation and amortization 8,030 5,769

60,166 35,941

Results from operating activities (46,037) (30,690)

Finance income 7,525 6,803

Finance expenses 8,10 (1,041) (1,361)

Net finance income 6,484 5,442

Loss before tax (39,553) (25,248)

Deferred income tax recovery 11 (8,693) (3,589)

Total loss and comprehensive loss for the year (30,860) (21,659)

Loss and comprehensive loss per common share 14

Basic $ (0.47) $ (0.38)

Diluted $ (0.47) $ (0.38)



ConsolIdAted stAtements of ChAnges In equIty Share Contributed(thousands of dollars) capital surplus Deficit Total equity

Balance at December 31, 2010 780,198 21,771 (4,173) 797,796

Comprehensive loss – – (21,659) (21,659)

Issuance of common shares 519,683 – – 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

Comprehensive loss – – (30,860) (30,860)

Issuance of common shares in exchange for assets 30,000 – – 30,000

Share-based payments – 8,335 – 8,335

Performance warrants exercised 10,578 (572) – 10,006

Performance share units exercised 2,377 (2,376) – 1

Replacement options exercised 1,720 (1,664) – 56

Stock options exercised 2,952 (791) – 2,161

Balance at December 31, 2012 1,333,979 31,410 (56,692) 1,308,697



ConsolIdAted stAtements of CAsh flows

For the years ended December 31(thousands of dollars) 2012 2011

Cash flows from operating activities

Comprehensive loss (30,860) (21,659)

Adjustments for:

Depreciation and amortization 8,030 5,769

Equity-settled share-based payments 4,657 4,227

Unwinding of site restoration discount 402 351

Deferred income tax recovery (8,693) (3,589)

Deferred income – (32)

(26,464) (14,933)

Change in trade and other receivables 777 (733)

Change in prepaid expenses and deposits (58) (153)

Change in inventories (1,889) (896)

Change in trade and other payables 3,064 4,948

Net cash used in operating activities (24,570) (11,767)

Cash flows from investing activities

Property, plant and equipment, and exploration and evaluation expenditures (236,600) (198,108)

Intangible expenditures (6,842) (5,667)

Abandonment deposits (9) (399)

Net cash used in investing activities (243,451) (204,174)

Cash flows from financing activities

Proceeds from the issuance of common shares 12,224 519,684

Finance lease obligation (5,210) (2,149)

Share issuance costs – (20,129)

Net cash from financing activities 7,014 497,406

Net increase (decrease) in cash and cash equivalents (261,007) 281,465

Cash and cash equivalents, beginning of year 656,891 375,426

Cash and cash equivalents, end of year 395,884 656,891



notes to the ConsolIdAted fInAnCIAl stAtements – deCember 31, 2012

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

1. repOrting entitYLaricina 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, 2012

encompass 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 preparatiOnStatement of compliance

These consolidated financial statements were prepared in accordance with International Financial Reporting

Standards (IFRS).

On April 4, 2013, the December 31, 2012 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, the Company’s functional currency.

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 and judgments are based on management’s best understanding of

current events and actions that the Company may undertake in the future. Actual results may differ from these estimates

and judgments. Significant estimates and judgments used in the preparation of the 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).


The amounts recorded for depreciation of E&E assets are based on estimates of useful life. Estimates and underlying

assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which

the estimates are revised.

IFRS requires that the Company’s oil sands assets be aggregated into cash generating units (CGUs), which are

classified based on their ability to generate independent cash flows which are used to assess assets for impairment.

The determination of the Company’s CGUs is subject to management’s judgment. Estimates of reserves and future

costs are used to assess impairment and are subject to measurement uncertainty. The decision to transfer assets from

E&E to PP&E is based on management’s assessment of technical feasibility and commercial viability, which is subject

to management’s judgment.

The site restoration provision is based on current legal and constructive requirements, technology, estimated costs

and expected timing for remediation. Actual costs can differ from estimated costs because of changes in laws and

regulations, discovery and analysis of site conditions and changes in technology.

Share-based payments are subject to estimation as they are calculated using the Black-Scholes option pricing model,

which is based on significant assumptions such as volatility and forfeiture rate.

3. summarY Of significant accOunting pOliciesThe 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

it 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 respective 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.


3. summarY Of significant accOunting pOlicies (continued)E&E assets are not depleted or amortized until the earlier of: the asset coming into 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 CGUs for purposes of determining whether or not the assets must be

transferred to the development and producing (D&P) category within PP&E and for performing impairment testing when

there are indicators of impairment. 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 assigned by independent reservoir engineers. Upon determination of proved reserves, E&E assets

attributable to these reserves are tested for impairment within the associated CGU and then transferred to D&P assets.

E&E assets that are in use as management intended are depreciated 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 depreciated when they are used to support the gathering of

reservoir information. The depreciation of these assets is recognized in comprehensive loss.

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.

Costs incurred subsequent to the determination of technical feasibility and commercial viability and 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. Such costs generally represent costs incurred in developing proved or probable

reserves and bringing on 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 comprehensive 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

comprehensive loss.

Intangible assets

Intangible assets consist of payments made to third parties to expand the availability of infrastructure for the Company’s

future development projects and the recapitalization of the depreciation of specific E&E assets.

Depreciation, depletion and amortization

The net carrying value of E&E assets is depreciated on a straight-line basis over estimated useful lives 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 plus 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 annually by independent

reservoir engineers.

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:

• areasonableassessmentofthefutureeconomicsofsuchproduction;

• areasonableexpectationthatthereisamarketforallorsubstantiallyalloftheexpectedproduction;and

• evidencethatthenecessaryproduction,transmissionandtransportationfacilitiesareavailableorcanreasonably

be made available.

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, provides support for the

engineering analysis on which the project was based.

For facilities and other equipment, depreciation is recognized in comprehensive loss on a straight-line basis over

their estimated useful life of 25 years. For corporate assets, depreciation is recognized in comprehensive 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.

Amortization of intangible assets – infrastructure expansion is recognized in comprehensive loss on a straight-line basis

over the term of the related contract.

Inventories

Inventories consist of materials, condensate, bitumen 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 bitumen blending and is valued at the lower of cost or net

realizable value with cost determined using a weighted-average cost. Bitumen blend inventory is produced bitumen that

has been blended with condensate 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.


3. summarY Of significant accOunting pOlicies (continued)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.

Minimum lease payments made under finance leases are allocated between finance expense and the reduction of the

outstanding liability.

Operating leases are not recognized in the Company’s statements of financial position. Payments made under operating

leases are recognized as expenses on a straight-line basis over the lease term.

Impairment

A financial asset is assessed at each reporting date for objective evidence indicating that impairment has occurred, such

as one or more events that might 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 comprehensive 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.

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 of assets that generates independent cash inflows from

continuing use, or the CGU. The recoverable amount of the asset or CGU is the greater of its value-in-use (VIU) 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 VIU, 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 asset’s specific risks. VIU 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 CGU exceeds its estimated recoverable amount.

Impairment losses are recognized in comprehensive loss and are reversed in subsequent periods if indicators exist such

that the impairment has decreased. The reversal of an impairment loss is the lower of the recoverable amount and the

carrying value of the asset, net of depreciation, amortization 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 its

activities 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 or 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 expenditures were provided for.

Share-based payment arrangements

The Company applies the fair value method for stock options and performance share units (PSUs) granted. Compensation

costs are recognized over the vesting period of the award based on the estimated fair value of the stock options or

PSUs 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 or

PSUs 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 (SARs), 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 product ownership 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 rate 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 comprehensive loss except

when they relate to items recognized directly in equity, or in other comprehensive income.


3. summarY Of significant accOunting pOlicies (continued)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.

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 common share issuance, the related resource expenditure deductions are renounced

to the shareholders in accordance with income tax legislation. Flow-through common shares issued are recorded in

share capital at the fair value of common shares on the date of issuance. The premium received on issuing flow-through

common 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 to the corresponding asset or expense when there is reasonable assurance of the collection of funding.

Earnings per share

Basic loss and comprehensive 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 replacement options, stock options and PSUs.

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 comprehensive loss and available-for-sale, are

measured at amortized cost determined using the effective interest rate method. Cash and cash equivalents are

comprised of cash balances and guaranteed investment certificates that may be redeemed at the Company’s option.

Trade and other receivables, and 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

The Company has reviewed the new standards and interpretations required for adoption for annual periods

beginning January 1, 2013 and determined that IFRS 7 Financial Instruments: Disclosures, IFRS 10 Consolidated

Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosure of Interests in Other Entities and IFRS 13 Fair

Value Measurement are relevant but not yet applicable to these financial statements. These standards are summarized

as follows:

• IFRS7hasbeenamendedtoclarifyrequirementsforoffsettingoffinancialassetsandfinancialliabilities,andto

enhance the corresponding disclosure requirements;

• IFRS10requiresanentitytoconsolidateaninvesteewhenitisexposed,orhasrightstovariablereturnsfromits

involvement with the investee and has the ability to affect those returns through its power over the investee;

• IFRS11requiresanentitytoclassifyitsinterestinajointarrangementasajointventureorjointoperation.Joint

ventures will be accounted for using the equity method of accounting and joint operations will be accounted for

by recognition of the entity’s share of the joint operation’s assets, liabilities, revenue and expenses;

• IFRS12establishesdisclosurerequirementsforinterestsinotherentitiessuchasjointarrangements,associates

and special purpose vehicles; and

• IFRS13isacomprehensivestandarddefiningfairvalueasthepricethatwouldbeexpectedtobereceivedtosell

an asset or paid to transfer a liability in a transaction between market participants at the measurement date, and

establishes disclosure requirements for fair value measurement across all IFRS.

The impact of the aforementioned standards has not yet been determined.

The Company has reviewed the new standards and interpretations required for adoption for annual periods beginning

January 1, 2014 and determined that International Accounting Standard (IAS) 32 Financial Instruments: Presentation is

relevant but not yet applicable to these financial statements. IAS 32 has been amended to clarify the requirements for

offsetting financial assets and financial liabilities and the corresponding disclosure requirements. This standard’s impact

is not yet determined.

The Company has reviewed the new standards and interpretations required for adoption for annual periods beginning

January 1, 2015 and determined that IFRS 9 Financial Instruments is relevant but not yet applicable to these financial

statements. IFRS 9 replaces IAS 39 Financial Instruments: Recognition and Measurement and uses a single approach

to determine whether a financial asset is measured at amortized cost or fair value, and requires a single impairment

method to be used. IFRS 9 may require different accounting for changes to the fair value of a financial liability as a result

of changes to an entity’s credit risk. The impact of this standard is not yet determined.


4. determinatiOn Of fair valuesCertain accounting policies and disclosures require the Company to determine fair value for purposes of measurement

or disclosure. Fair values have been determined using 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.


Level 2 fair value measurements are based on valuation models and techniques where the significant inputs are derived

from quoted indices.

For stock options, PSUs, and SARs 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 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 and cash equivalents, 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 interest rate at the reporting date. At

December 31, 2012 and December 31, 2011 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, PSUs and SARs is measured using the Black-Scholes option pricing model. Measurement

inputs include the common 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

SARs has been assessed at a Level 2 fair value measurement as the significant inputs are derived from market prices

for the underlying common shares, volatility based on historical prices of publicly-traded peer companies and published

risk-free interest rates.


5. inventOries December 31 December 31 2012 2011

Condensate 120 123

Materials 2,109 946

Bitumen blend 101 92

Other 1,025 579

3,355 1,740

6. OtHer lOng-term assetsAt December 31, 2012, the Company had investment tax credits of $1.2 million ($1.2 million at December 31, 2011). 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 ($0.9 million at December 31, 2011). The

investment tax credits will be used to offset current income taxes payable and begin to expire in 2026.

7. explOratiOn and evaluatiOn assets

Cost

Balance, December 31, 2010 425,806

Additions during the year 219,451


Additions during the year 255,996

Transferred to PP&E (9,230)


Depreciation

Balance, December 31, 2010 –

Depreciation for the year (6,852)

Balance, December 31, 2011 (6,852)

Depreciation for the year (10,817)

Balance, December 31, 2012 (17,669)

Carrying amounts

As at December 31, 2011 638,405

As at December 31, 2012 874,354


7. explOratiOn and evaluatiOn assets (continued)

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

year. During the year ended December 31, 2012, $9.2 million was transferred to PP&E for costs associated with road

upgrades. No amounts were transferred to PP&E during the year ended December 31, 2011.

In May 2011 the Company began selling bitumen produced 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 comprehensive loss. The depreciation of assets providing additional

reservoir information has been recapitalized as intangible assets.

On July 19, 2011 the Government of Alberta announced that the Company had been selected to receive funding of up

to $10.0 million (gross) under the Innovative Energy Technologies Program for the Saleski pilot. The funds are being

recorded as a reduction to the corresponding E&E asset when received. As at December 31, 2012, $8.2 million gross

($4.9 million net) has been recorded as a reduction of the costs associated with the Saleski pilot. As at December 31, 2011

$5.5 million gross ($3.3 million net) had been recorded as a reduction of the costs associated with the Saleski pilot.

8. prOpertY, plant and equipment Facilities and other Corporate equipment assets Total

Cost

Balance, December 31, 2010 30,201 2,474 32,675

Additions during the year 15,264 1,643 16,907



Transferred from E&E 9,230 – 9,230


Depreciation

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)

Depreciation for the year (1,961) (993) (2,954)

Balance, December 31, 2012 (4,374) (2,849) (7,223)

Carrying amounts

As at December 31, 2011 43,052 2,261 45,313

As at December 31, 2012 81,106 3,481 84,587


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, 2012 assets held under finance lease have a

gross carrying value of $15.0 million ($15.0 million at December 31, 2011) and accumulated depreciation of $1.2 million

($0.6 million at December 31, 2011) and are included in facilities and other equipment.

9. intangiBle assets Depreciation Infrastructure of E&E expansion assets Total

Cost

Balance, December 31, 2010 – – –





Amortization


Amortization for the year – – –


Amortization for the year (156) – (156)

Balance, December 31, 2012 (156) – (156)

Carrying amounts

As at December 31, 2011 5,667 3,284 9,491

As at December 31, 2012 12,353 10,178 22,531

At December 31, 2012, the Company had intangible assets of $12.5 million ($5.7 million at December 31, 2011) 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 amortization of this asset commenced during 2012 when the expansion was completed and

will be recognized over the term of the contract with the third-party provider.

At December 31, 2012, the Company had intangible assets of $10.2 million ($3.8 million at December 31, 2011) 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 reclassified as an intangible asset.


10. site restOratiOn prOvisiOn


Provisions made during the year 8,916

Revisions (change in estimates) (457)

Revisions (change in discount rate) 2,621

Unwinding of discount 351


Provisions made during the year 1,508

Revisions (change in estimates) 543

Revisions (change in discount rate) 351

Unwinding of discount 402


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, infrastructure and camps, estimated costs to reclaim and

abandon these assets 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 obligations to be $19.0 million as at December 31, 2012 ($16.2 million at

December 31, 2011) based on an undiscounted total future liability of $35.8 million ($32.5 million at December 31, 2011).

These obligations are expected to be settled over the next 28 years with the majority of the costs to be incurred between

2025 and 2040. The discount factor, being the risk-free rate related to the liability, was 2.4 percent at December 31, 2012

(2.5 percent at December 31, 2011).

11. incOme taxesThe provision for income taxes differs from the amount which would be expected by applying the combined federal and

provincial 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 2012 2011

Loss before income taxes (39,553) (25,248)

Canadian statutory income tax rate (percent) 25.00 26.50

Expected income tax recovery at statutory rate (9,888) (6,691)

Increase (decrease) in income taxes resulting from:

Reduction in effective tax rate – 314

Non-deductible costs 1,195 1,110

Flow-through share renunciation – 3,915

(8,693) (1,352)

Flow-through share premium – (2,237)

Income tax recovery (8,693) (3,589)


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 combined federal-provincial statutory corporate income tax rate decreased to 25.00 percent in 2012 from

26.50 percent in 2011 as a result of tax legislation enacted in 2007.

The temporary differences that give rise to the deferred tax assets and liabilities in the years ended December 31 are

as follows:

2012 2011

Deferred tax liabilities

PP&E and E&E assets 65,107 52,855

Deferred tax assets

Non-capital losses (58,976) (36,225)

Share issuance costs (4,421) (6,227)

(63,397) (42,452)

1,710 10,403

Movement in deferred tax balances during the year ended December 31, 2012:

Recognized Beginning Recognized directly in End of year in loss equity of year

PP&E and E&E assets 52,855 12,252 – 65,107

Non-capital losses (36,225) (22,751) – (58,976)

Share issuance costs (6,227) 1,806 – (4,421)

10,403 (8,693) – 1,710

Movement in deferred tax balances during the year ended December 31, 2011:

Recognized Beginning Recognized directly in End of year in loss equity of year

PP&E and E&E assets 28,175 24,680 – 52,855

Non-capital losses (7,883) (28,342) – (36,225)

Share issue costs (3,515) 2,310 (5,022) (6,227)

16,777 (1,352) (5,022) 10,403

As at December 31, 2012, the Company has non-capital losses of $235.6 million which begin to expire in 2025.


12. credit facilitYThe Company’s credit agreement with a Canadian chartered bank has been extended to October 31, 2013. 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, 2012 and April 4, 2013 the Company had issued letters of

credit totalling $3.0 million under the credit facility and no amount had been drawn.

13. sHare capital Authorized

Unlimited number of common shares without par value

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

Number of shares (thousands) Amount

Common Shares

Balance, December 31, 2010 51,916 780,198

Issued for cash 12,228 519,683

Share issuance costs, net of tax benefit – (15,065)

Performance share units exercised 67 1,536

Balance, December 31, 2011 64,211 1,286,352

Issued in exchange for assets 706 30,000

Performance warrants exercised 853 10,578

Performance share units exercised 89 2,377

Replacement options exercised 1,121 1,720

Stock options exercised 123 2,952

Balance, December 31, 2012 67,103 1,333,979

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).

On February 15, 2012, the Company acquired the remaining working interests in jointly-controlled oil sands

properties effective January 1, 2012 for total consideration of $30.0 million consisting of 705,882 common shares valued

at $42.50 per common share.


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

entitling the holder to receive one common share for each warrant exercised.

2012 2011

Weighted Weighted average average Number exercise Number exercise (thousands) price (thousands) price

Outstanding, beginning of year 4,071 $ 11.20 4,071 $ 11.20

Exercised (853) 11.73 – –

Exchanged for replacement options (3,218) 11.06 – –

Outstanding, end of year – $ – 4,071 $ 11.20

Exercisable, end of year – $ – 4,071 $ 11.20

The fair value calculation for performance warrants was not required during the years ended December 31, 2012 and

December 30, 2011 as no performance warrants were issued or required a change in measurement.

Replacement options

On June 18, 2012, the Company entered into a replacement option agreement with certain directors, officers and

employees whereby the holders of specific options and performance warrants exchanged their rights to these options

and performance warrants for replacement options. The economic value of the rights exchanged equalled the economic

value of the replacement options granted on the date of the exchange. The replacement options expire on June 18, 2014

and for each replacement option exercised the holder will receive one common share.

Weighted average Number exercise (thousands) price

Outstanding, December 31, 2011 – $ –

Exchange of certain performance warrants and options 3,559 0.05

Exercised (1,121) 0.05

Outstanding, December 31, 2012 2,438 $ 0.05

Exercisable, December 31, 2012 954 $ 0.05


13. sHare capital (continued)Stock option plan

The Company has a stock option plan under which directors, officers, employees of, and providers of services to the

Company are eligible to receive grants of options. The exercise price and vesting period of options granted is determined

by the Board of Directors at the time of grant.

2012 2011


Outstanding, beginning of year 3,485 $ 16.12 3,083 $ 13.50

Granted 717 30.31 428 35.95Exercised (123) 17.57 – –Forfeited (412) 30.14 (26) 32.39

Exchanged for replacement options (1,690) 5.00 – –

Outstanding, end of year 1,977 $ 27.76 3,485 $ 16.12

Exercisable, end of year 910 $ 24.89 2,498 $ 11.09

Outstanding and exercisable options as at December 31, 2012:

Outstanding Exercisable

Weighted Weighted Weighted average average average remaining exercise exercise Number contractual price Number priceExercise price ($/option) (thousands) life (years) ($/option) (thousands) ($/option)

10.00 – 14.99 46 1.1 12.50 46 12.50

15.00 – 19.99 15 3.9 15.00 10 15.00

20.00 – 24.99 643 2.9 20.16 469 20.00

25.00 – 29.99 170 6.7 28.44 2 25.00

30.00 – 34.99 811 4.6 31.63 359 32.17

35.00 – 39.99 244 5.2 35.20 11 36.10

40.00 – 44.99 48 5.6 42.50 13 42.50

1,977 4.2 27.76 910 24.89

For the year ended December 31, 2012, compensation cost of $4.4 million ($3.8 million in 2011) was recognized for

options granted of which $1.7 million ($2.0 million in 2011) 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:

2012 2011

Fair value per option $ 18.76 $ 14.72

Expected volatility (percent) 63.1 33.5

Risk-free interest rate (percent) 1.6 2.8

Expected life (years) 7 7

Expected dividend yield – –

A forfeiture rate of 5.0 percent in 2012 (2.0 percent in 2011) 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

behaviour 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 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, 2012 have a weighted-average remaining contractual life

of 5.0 years.

2012 2011


Outstanding, beginning of year 675 $ 0.01 555 $ 0.01

Granted 327 0.01 204 0.01Exercised (89) 0.01 (67) 0.01

Forfeited (117) 0.01 (17) 0.01

Outstanding, end of year 796 $ 0.01 675 $ 0.01

Exercisable, end of year 250 $ 0.01 159 $ 0.01

For the year ended December 31, 2012, compensation cost of $4.0 million ($4.5 million in 2011) was recognized for

PSUs granted of which $1.6 million ($2.4 million in 2011) was capitalized.


13. sHare capital (continued)The estimated fair value of PSUs was calculated at the date of grant using the Black-Scholes model and the following

weighted-average assumptions:

2012 2011

Fair value per option $ 29.46 $ 36.60



Expected life (years) 7 7


A forfeiture rate of 5.0 percent in 2012 (2.0 percent in 2011) 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 behaviour and the risk-free interest rate is based on Government of Canada bonds of

a similar duration.

Share appreciation rights

The Company has a SARs plan under which directors, officers, employees of, and providers of services to the Company

are eligible to receive grants of 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.

2012 2011


Outstanding, beginning of year 77 $ 33.13 36 $ 26.88

Granted 146 30.22 60 35.95Exercised (14) 25.15 (11) 25.94Expired (6) 30.00 – –

Forfeited (58) 32.87 (8) 35.49

Outstanding, end of year 145 $ 31.20 77 $ 33.13

Exercisable, end of year 17 $ 35.00 6 $ 27.81

All SARs were granted to employees directly involved in field activities. For the year ended December 31, 2012,

compensation cost of $0.3 million ($0.3 million in 2011) was recognized for SARs granted. At December 31, 2012, the

Company had recorded an accrued liability of $0.6 million ($0.3 million at December 31, 2011) for outstanding SARs. At

December 31, 2012, the Company had an obligation of nil (nominal at December 31, 2011) for SARs that had vested.


The estimated fair value of SARs for the year ended December 31, 2012 was calculated at the date of grant using the

Black-Scholes model and the following weighted-average assumptions:

2012 2011

Fair value per SAR $ 10.78 $ 6.95

Share price $ 30.22 $ 35.95

Exercise price $ 30.22 $ 35.95



Expected life (years) 2.0 2.0


A forfeiture rate of 20.0 percent was applied for grants issued during the year ended December 31, 2012 (10.0 percent

in 2011), 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

behaviour and the risk-free interest rate is based on Government of Canada bonds of a similar duration.

14. lOss and cOmpreHensive lOss per sHareBasic loss and comprehensive loss per share

The calculation of basic loss and comprehensive loss per share for the year ended December 31, 2012 was based on

the loss and comprehensive loss attributable to common shareholders of $ 30.9 million ($21.7 million in 2011) and the

weighted-average number of common shares outstanding during the year, calculated as follows:

(thousands) 2012 2011

Issued common shares at beginning of year 64,211 51,916

Effect of common shares issued 617 5,763

Effect of performance warrants exercised 425 –

Effect of PSUs exercised 46 –

Effect of replacement options exercised 379 –

Effect of stock options exercised 46 47

Weighted-average common shares outstanding (basic) 65,724 57,726

Diluted loss and comprehensive loss per share

The calculation of diluted net loss and comprehensive loss per share does not include performance warrants, options or

PSUs as the effect would be anti-dilutive.

The basic and diluted loss and comprehensive loss per share was $0.47 for the year ended December 31, 2012,

compared to $0.38 for the year ended December 31, 2011.


15. OtHer incOmeOther income is composed of the following:

2012 2011

Data sale to third party 1,200 2,700

Third-party camp and road usage 7,316 192

8,516 2,892

16. persOnnel expensesThe aggregate payroll expenses of employees and executive management are as follows:

2012 2011

Wages and salaries 16,207 11,885

Benefits and other personnel costs 4,644 2,875

Share-based payments 7,571 8,770

Total remuneration 28,422 23,530

Capitalized portion of total remuneration (11,376) (11,496)

17,046 12,034

Personnel expenses directly related to E&E activities were capitalized and included in E&E assets.

17. Operating leasesNon-cancellable operating lease rentals as at December 31 are payable as follows:

2012 2011

Less than one year 8,472 9,414

Between one and five years 17,403 19,921

25,875 29,335


18. executive cOmpensatiOnIn addition to salaries, the Company provides non-cash benefits to executive officers through participation in the

Company’s stock option and PSU plans.

Executive officer compensation costs for the years ended December 31 are comprised of the following:

2012 2011

Salaries 1,808 1,835

Other short-term employment benefits 965 969

Share-based payments 1,930 2,031

4,703 4,835

Share-based payments represent the amortization of compensation costs associated with grants of stock options and

PSUs to executive officers as recorded in the financial statements.

19. 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, 2012 or 2011.

The carrying amount of financial assets represents the maximum credit exposure, as follows:

December 31 December 31 2012 2011

Cash and cash equivalents 395,884 656,891

Trade and other receivables 7,923 17,892

403,807 674,783


19. financial risk management (continued)

The maximum exposure to credit risk for trade and other receivables by type of customer was:

December 31 December 31 2012 2011

Joint venture partners 1,240 3,466

Other 6,683 14,426

7,923 17,892

The Company’s most significant receivable at December 31, 2012 was $2.1 million for third-party camp revenue. The

Company’s most significant receivable at December 31, 2011 was $5.5 million, for the sale of data to a third party.

As at December 31, 2012, the Company’s trade and other receivables were aged based on due date with

$5.8 million classified as current (less than 30 days). The $2.1 million overdue account was collected subsequent to

December 31, 2012. As at December 31, 2011, all the Company’s trade and other receivables of $17.9 million were

classified as current.

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 its reputation.

Laricina prepares annual capital and operating expenditure budgets that are monitored on a regular basis and updated

as necessary.

As at December 31, 2012, cash was held in a fully-liquid, interest-bearing operating account and Laricina had

$12.0 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:

2012 2011

Less than one year

Trade and other payables 54,531 44,210

Finance lease obligation 7,641 5,000

62,172 49,210

Between one and three years

Finance lease obligation – 7,851

62,172 57,061


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, 2012.

Laricina is not subject to externally imposed capital restrictions; the credit facility referred to in note 12, however, is

secured by an equivalent cash deposit.

20. capital cOmmitmentsAt December 31, 2012, the Company had purchase orders outstanding of $54.2 million for the purchase of E&E assets,

all of which are due within one year.

At December 31, 2011, the Company had purchase orders outstanding of $61.4 million for the purchase of E&E assets.


Glen C. SchmidtPresident and Chief Executive OfficerCalgary, Alberta

C. Dean SetoguchiSenior Vice President and Chief Financial OfficerCalgary, Alberta

Derek A. KellerVice President ProductionCalgary, Alberta

Karen E. LillejordVice President Finance and ControllerCalgary, Alberta

James R. HandSenior Vice President and Chief Operating OfficerCalgary, Alberta

Mr. Schmidt has more than 30 years of oil and gas experience with more than 20 years at the executive level. He has been President and Chief Executive Officer of Laricina since inception in 2005. He holds a Master of Business Administration and Bachelor of Science in Chemical Engineering (with Distinction) from the University of Calgary and is a member of the Association of Professional Engineers and Geoscientists of Alberta.

David SafariVice President FacilitiesCalgary, Alberta

Mr. Safari has more than 26 years of experience in the energy industry, domestically and internationally. He has been with Laricina since 2012. Mr. Safari holds a Bachelor of Science in Chemical Engineering from the Sharif University of Technology in Tehran, Iran and is a member of the Association of Professional Engineers and Geoscientists of Alberta and the Association of Professional Engineers and Geophysicists of Saskatchewan.

Mr. Setoguchi has more than 20 years of experience in capital markets, investor relations, financing, treasury and strategic planning. He has been Senior Vice President and Chief Financial Officer at Laricina since 2012. Mr. Setoguchi holds a Bachelor of Management from the University of Lethbridge and is a Chartered Accountant.

Mr. Keller has 20 years of oil and gas experience, primarily in heavy oil and oil sands. He has been with Laricina since 2006. Mr. Keller holds a Bachelor of Science in Chemical Engineering from the University of Alberta and is a member of the Association of Professional Engineers and Geoscientists of Alberta.

Ms. Lillejord has 28 years of experience in a variety of functions, primarily in the area of corporate reporting. She has been with Laricina since inception in 2005. Ms. Lillejord holds a degree in Business Administration from the University of Regina and has obtained the designations of Chartered Accountant, Certified Management Accountant and Certified Public Accountant.

Mr. Hand has more than 30 years of oil and gas experience in a variety of technical, managerial and leadership positions, domestically and internationally. He has been Senior Vice President Operations and Chief Operating Officer at Laricina since 2013. Mr. Hand holds a Bachelor of Science in Petroleum Engineering from Texas A&M University and is a registered Professional Engineer in the State of Alaska.

Laricina ManageMent teaM

Marla A. Van GelderVice President Corporate DevelopmentCalgary, Alberta

Ms. Van Gelder has 23 years of combined experience in banking, finance and oil and gas. She has been with Laricina since 2006. Ms. Van Gelder holds a Bachelor of Commerce from the University of Calgary and has obtained her designation as a Certified General Accountant and is a Chartered Financial Analyst charterholder.


Laricina Board of directors

Ian D. BruceCalgary, Alberta

Robert A. Lehodey, Q.C.Calgary, Alberta

Jeffrey M. Donahue, Jr.Toronto, Ontario

W. Glen RussellCalgary, Alberta

Brian K. LemkeCalgary, Alberta

Jonathan C. FarberWestport, Connecticut, USA

Glen C. SchmidtCalgary, Alberta

S. Barry JacksonCalgary, Alberta

Gordon J. KerrCalgary, Alberta

Independent investor. Mr. Bruce is also a director of Cameco Corporation, Logan International Inc., TriAxon Oil Corp., Northern Blizzard Resources Inc. and PumpWell Solutions Ltd. Formerly Chief Executive Officer and Co-Chairman of Peters & Co. Limited.

Partner, Osler, Harkin & Harcout LLP since March 9, 2006. Mr. Lehodey is also a director of Delphi Energy Corp and a number of other private companies.

Independent businessman and investor. Formerly Chairman, Cordero Energy Inc. from April 2005 to November 2008.

Principal, Glen Russell Consulting since October 1998. Mr. Russell is also Chairman of Accolade Capital Inc.

President and Chief Executive Officer of Laricina Energy Ltd. since November 2005. Mr. Schmidt is also a director of Elkhorn Resources Inc. and Argent Energy Trust.

Vice President – Principal Investing, CPPIB Equity Investments Inc. since October 5, 2009. Vice President, Strategy and Business Development with BHP Billiton PLC in London from September 2003 to 2009.

Managing Director, Lime Rock Management LP, an investment management firm, since June 1998.

Chairman, TransCanada Corporation since April 29, 2005. Mr. Jackson is also a director of Nexen Inc. and WestJet Airlines Ltd.

President and Chief Executive Officer, Enerplus Corporation since May 10, 2001.


corPorate inforMationAuditorsKPMG LLP

BAnkersCanadian Imperial Bank of Commerce

solicitorsOsler, Hoskin & Harcourt LLP

reservoir engineersGLJ Petroleum Consultants Ltd.

registrAr And trAnsfer AgentEquity Financial Trust Company

AnnuAl generAl MeetingThe Annual General Meeting of

Laricina’s shareholders will take

place on May 22, 2013 at 10:00 am

MDT in the Metropolitan Ballroom of

the Metropolitan Centre, at 333-4th

Avenue SW, Calgary, Alberta.

senior MAnAgeMentGlen C. SchmidtPresident and CEO

James R. HandSenior Vice President and COO

C. Dean SetoguchiSenior Vice President and CFO

Derek A. KellerVice President Production

Karen E. LillejordVice President Finance and Controller

David SafariVice President Facilities

Marla A. Van GelderVice President Corporate Development

directorsBrian K. Lemke (1) (2C)

Independent investor

Ian D. Bruce (2) (4)

Independent investor

Jeffrey M. Donahue, Jr. (2) (3)

Vice President – 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. SchmidtPresident and CEO, Laricina Energy Ltd.

(1) Chairman of the Board (2) Audit Committee (3) Governance & Human Resources Committee (4) Technical Committee (C) Committee Chairman

Forward-Looking Statements

This annual report contains certain “forward-looking statements” under applicable securities laws and includes such statements about Laricina Energy Ltd.’s plans that are based on assumptions and that involve risk and uncertainties. Actual results may differ materially. Refer to page 46 for additional information on forward-looking statements.

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This isLaricina

from prospects to recognized assets. from simulation and testing to drilling and production. from ideas to innovation. from resources to reserves. since its founding in 2005, Laricina’s story has been one of acting on ideas, of fulfilling commitments – of producing.

Germain Commercial Demonstration Project (CDP)

2 We Produce Value 4 We Define Growth 6 We Foster Innovation11 We Create Decades of

Future Growth and Value12 President’s Letter18 We Produce Bitumen from

the Grosmont at Saleski26 We Are Building at Germain34 We Unlock Growth Opportunities36 We Advance In Situ Technologies

and Innovation38 We Engage Communities and

Operate Safe Projects

40 We Have Built a Dedicated Team41 Reserves and Resources46 Management’s Discussion and Analysis67 Independent Auditors’ Report68 Consolidated Financial Statements72 Notes to the Consolidated

Financial Statements96 Laricina Mangement Team97 Laricina Board of Directors98 Corporate InformationIBC Glossary and Abbreviations

GlossaryAESRD Alberta Environment and Sustainable Resource Development

C-SAGD cyclic steam-assisted gravity drainage

CSS cyclic steam stimulation

CDP commercial demonstration project

CPF central processing facility

ERCB Energy Resources Conservation Board

ESEIEH Enhanced Solvent Extraction Incorporating Electromagnetic Heating

GLJ GLJ Petroleum Consultants Ltd., independent engineering and geological services firm

HSE health, safety and environment

IFRS International Financial Reporting Standards

OASIS Open-Access Simulation Integrated System

PHARM Passive Heat-Assisted Recovery Method

SAGD steam-assisted gravity drainage

SC-SAGD solvent-cyclic steam-assisted gravity drainage

SOR steam-to-oil ratio

abbreviaTions°C degrees Celsius

% percent

bbls barrels

bbls/d barrels per day

D darcy

kH horizontal permeability

km kilometre(s)

kV kilovolt(s)

kV vertical permeability

m metre(s)

m3 metres cubed

mmbbls million barrels

MMBtu million British thermal units

MPa megapascal(s)

PV10 net present value, before tax, 10 percent discount

square-km square kilometres

Laricina En

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2012 AnnuAl RepoRt

We Produce

Value I Growth I Innovation

Head OfficeLaricina energy Ltd.eAst toweR, FIFtH AVenue plAcesuIte 800, 425 – 1st stReet swcAlgARy, Ab t2p 3l8 P i 403.750.0810f i 403.263.0767

Wabasca cOmmunity engagement OfficeLaricina energy Ltd.2155 MIstAssInIy RoAdp.o. box 540wAbAscA, Ab t0g 2K0

P i 780.891.3352f i 780.891.3359

Laricinaenergy.cOm

201 annual report - laricina energy rouse, team lead, production operations engineering we are an in...

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