Candax Annual Report - 2010

2010ANNUALREPORT

130 ADELAIDE STREET WEST, SUITE 1010TORONTO, ONTARIO, CANADA M5H 3P5T + 416.368.9137F + 416.364.5400E [email protected]

Candax Energy Inc. (“Candax”)is a Canadian independent, internationaloil and gas exploration, development andproduction company. The Company’s primaryobjective is to increase shareholder value bybuilding a sustainable, international upstreamcompany focused on opportunities in Africa andthe Middle East.

TABLE OF CONTENTS1 Achievements from 2010 and Objectives for 20112 Message to Our Shareholders4 Report on Operations8 Board of Directors9 Management’s Discussion and Analysis23 Forward-Looking Statements24 Management’s Responsibility for Financial Reporting25 Independent Auditor’s Report26 Consolidated Balance Sheets27 Consolidated Statements of Operations and Deficit28 Consolidated Statements of Cash Flows29 Consolidated Statements of Comprehensive Loss30 Notes to the Consolidated Financial Statements41 Corporate Information

New Logo Introduction

Candax is clearly a company reborn with a clean image and a new management team. The logo incorporates theindustry's universal colours for oil and gas of green and red with the flocks of green and red colour representingboth production and share growth. A bold and custom typeface was created to communicate a sense of confidenceand stability and ultimately represent the new image of Candax.

DIRECTORS AND OFFICERS

Benoit DebrayChairman

Dr. Richard J. H. NorrisPresident, CEO and Director

M’hamed Ali BouleymanDirector and Chairman,Ecumed Petroleum

Stephen DrinkwaterDirector

Christopher O. IrwinDirector

Thomas RebillyDirector

Matthieu MilandriChief Financial Officer

Pascal MirvilleChief Operating Officer andGeneral Manager, Tunisian OperationsEcumed Petroleum

Charlotte M. MayCorporate Secretary

BOARD SUB-COMMITTEEMEMBERSHIPAudit CommitteeM'hamed Ali Bouleymen – ChairmanBenoit DebrayChristopher O. Irwin

Compensation CommitteeBenoit DebrayStephen DrinkwaterThomas Rebilly

Governance CommitteeChristopher O. Irwin – ChairmanBenoit DebrayStephen DrinkwaterThomas Rebilly

Disclosure CommitteeBenoit Debray – ChairmanCharlotte M. MayMatthieu MilandriDr. Richard J. H. Norris

EXECUTIVE HEAD OFFICE130 Adelaide Street West, Suite 1010Toronto, Ontario, Canada M5H 3P5T + 416.368.9137F + 416.364.5400E [email protected]

TUNISIA OFFICEEcumed PetroleumRue du Lac WindermereLes Berges du Lac1053 Tunis, TunisiaT + 216.71.962.611F + 216.71.963.765

MADAGASCAR OFFICECandax Madagascar LtdImmeuble SANTALot III - 3è EtageAntanimenaAntananarivo 101MadagascarT + 261.20.22.265.58F + 261.20.22.265.81

INVESTOR RELATIONSCHF Investor Relations90 Adelaide Street West, 6th FloorToronto, Ontario, Canada M5H 3V9T + 416.868.1079F + 416.868.6198

AUDITORSPricewaterhouseCoopers LLPRoyal Trust Tower, TD Centre77 King Street WestSuite 3000, PO Box 82Toronto, Ontario, Canada M5K 1G8

BANKINGBank of MontrealMain Branch – 1 First Canadian Place100 King Street WestToronto, Ontario, Canada M5X 1A3

INDEPENDENT ENGINEERSRyder Scott Company1200, 530 - 8th Avenue SWCalgary, Alberta, Canada T2P 3S8

LEGAL COUNSELMcCarthy Tétrault LLPBox 48, Suite 5300Toronto Dominion Bank TowerToronto, Ontario, Canada M5K 1E6T + 416.362.1812F + 416.868.0673

McGrigors5 Old BaileyLondon EC4M 7BADX 227 London Chancery LaneTel: +44 (0)207 054 2500Fax: +44 (0)207 054 2501

TRANSFER AGENTEquity Financial Trust Company200 University Avenue, Suite 400Toronto, Ontario, Canada M5H 4H1T + 416.361.0152F + 416.361.0470E: [email protected]

TSX: CAXwww.candax.com

ANNUAL & SPECIAL MEETINGTuesday, June 28 at 10 am at theCorporation’s head office.130 Adelaide Street West, Suite 1010Toronto, Ontario, Canada M5H 3P5

Print date: May 24, 2011

Corporate Information

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DELIVERINGON OUROBJECTIVES

Achievements from 2010

Restructured balancesheet, significantlyreducing the debt burden.

Successfully re-connectedthe El Bibane 3 well andrestarted productionin September 2010.

The Ulysse drilling rigarrived and the Ezzaouiawork-over and side-track program wasmostly completed.

Obtained a one-year extensionto the Madagascar Block 1101exploration permit andprogressed EnvironmentalImpact Assessments and adrilling permit.

Objectives for 2011

With minor exceptions, the objectives for 2011, in terms of field operationsare discretionary and will be completed and/or accelerated where possible,depending on the finances available to Candax.

• Work-over Robbana-1 well, with data acquisition and restart production

• Reprocess existing seismic on all properties in Tunisia – Robbana, El Bibaneand Ezzaouia in priority

• Acquisition of 3D on El Bibane and on Robbana – subject to proof of needfrom reprocessed existing data

• Complete full-field numerical simulation study of El Bibane to optimizesubsequent exploitation of the field

• Integration of the new seismic data/interpretations

• Development of an optimised field exploitation plan –for execution in 2012

• Progress planning of a full-field enhanced oil recovery plan, based onwater-flooding, for Robbana

• Implementation of the initial stages of this plan in the fourth quarter,with the drilling of an injector-producer pair

• Complete the required works on Block 1101 Madagasacar to move into thesecond exploration period and potentially farm-down Candax’s ParticipatingInterest in the block

• Ensure adequate financing flexibility in the short and medium term to enablethese capital programs

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At the time of last year’s annual report, Candaxwas facing challenges on many fronts. Today, it isvery gratifying to note that, although challengesremain, very significant progress has been madeand we have a clear road map for growth.


To Our Shareholders

DELIVERINGIS A PROCESS

It is a great pleasure that we are writing this letter one yearinto our stewardship of Candax. At the time of last year’sannual report, Candax was facing challenges on manyfronts. Today, it is very gratifying to note that, althoughchallenges remain, very significant progress has beenmade and we have a clear road map for growth.

2010 was a year of major changes and upheaval for Candax.At the beginning of 2010, Candax board and managementwere working intensively to resolve the liquidity issues whichresulted in investment by Geofinance N.V. and a significantchange in the board and executive management. By theend of 2010, Candax had negotiated a reduction of its debtburden by half, and notably, negotiated a two year graceperiod for repayments, an essential time frame thatprovides Candax with the ability to properly evaluateand bring its assets back into production. Such a radical

turn-around was made possible thanks to the effortsof Candax’s management and board and crucially thesupport and belief of Candax’s new major shareholder,namely Geofinance.

At the time of writing last year’s letter to shareholders,production was at an all time low, with El Bibane remainingoff-line despite a light work-over in March 2010, a longdelayed work-over and side-track campaign was set tocommence on the Ezzaouia field and the Robbana fieldwas shut-in. By the end of 2010 production albeit limitedwas successfully restored to El Bibane and quality upsidehad been quantified in non-producing assets.


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located onshore a stepwise approach to investmentcan be applied, with initial wells adding data (as wellas production), with an iterative approach to optimizingthe overall development.

2011 will also be focused on significant amounts of dataacquisition and field studies. Although we would want tosee the results soonest, it is important to recognize that theprocess will take up most of the year and we are unlikely tosee any direct activity to increasing production on El Bibaneuntil 2012. Ezzaouia is also the subject of on-going studies,and we anticipate that these will bear fruit both in 2011via individual well optimizations and in 2012 by additionalinfill wells.

We aim to increase production from across the range ofassets – producing, shut-in, non-producing and indeedexploration. This will not happen overnight, but we arededicated to delivering by implementing best oil fieldtechnology and practices.

In closing, we want to take this opportunity to thank allour staff at Candax, Ecumed and in Madagascar for theircommitment in seeing Candax through the challenges of2010. And, we also thank you, our shareholders, for yourconfidence and patience as we work on delivering theproduction needed to restore Candax to profit and tore-establish your E&P company.

In May 2010 the long awaited Ulysses rig arrived in Tunisiagoing directly to the Ezzaouia Field and work commenced onthe delayed drilling and work-over campaign. This campaignhad mixed results with the Ezzaouia 5 well side-trackencountering unexpectedly depleted levels in the Zeebag anddisappointing work-overs on the Ezzaouia 1, Ezzaouia 11 andEzzaouia 9 wells. Although further work is required to optimizeproduction from these wells, initial results are promising. Asof the writing of this letter, we are also pleased to report thatthe Ezzaouia 2 side-track has shown positive indications fromopen hole logging and is being readied for production.

On the El Bibane field, the El Bibane 3 well was worked-overin August 2010 and despite finding the tubing to be broken inmore than one place, production was restored via a new tubingstring anchored above the irretrievable broken tubing andpacker. At the time of the work-over, the field had beenoff line for just over a year, and at start-up, it was clearthat production levels seen before the tubing broke in August2009, were unlikely to be resumed immediately. By year end,production still required artificial lift, with no sign of the wellresuming natural flow as the gas-cap had recompressedduring the shut-in period.

On the main non-producing assets, Chaal and Madagascarwere much in focus as well as former producers Al Manzahand Belli and our highly prospective Deep Triassic target. Afterhaving worked hard to find and close a farm-in deal on theChaal discovery, it was a major disappointment to have thepermit annulled when it expired in May 2010. At Madagascar,the first major milestone was achieved in obtaining a year’sextension to the exploration permit in June. Subsequent tothis, we progressed the necessary logistical and environmentalworks necessary as preparation for completing the agreedwork program in 2011. Candax firmly believes that the shut-inBelli and Al Manzah fields have potential, and we are workingactively to maximize our opportunities to drill the high-impactDeep Triassic prospect that underlies the El Bibane andEzzaouia fields.

Candax has a well balanced portfolio of assets comprisingboth exploration and production assets, however our focusin 2010 was on delivering near-term production. We believefirmly in the upside potential of Candax’s exploration assets,but we do not take our eyes off the bottom line – productionand revenues are necessary to underpin exploration spend inan E&P company.

Delivering on the strength provided by the corporaterestructuring, Candax will be progressing multiple vectors forgrowth in 2011. Foremost is the development of Robbana. Thefield is proven to have significant volumes of oil in place, andto-date a very low recovery factor due to a lack of energy in thereservoir. Energy can be added by water-injection and althoughit is too early to predict the likely recoveries, Robbana hasexcellent potential and is likely to be a key driver in Candax’sshort, medium and long term growth. Having just one well inthe field underscores the difficulty of characterizing the fieldand the likely response to water-flooding, however being

We aim to increaseproduction from acrossthe range of assets –producing, shut-in,non-producing andindeed exploration.This will not happenovernight, but we arededicated to deliveringby implementing bestoil field technologyand practices.



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A restructured balance sheet and a strongsupportive shareholder give Candax the platformand time necessary to fully deliver the promise ofthe Candax assets.

Robbana takes front and centre position. The field has produced small volumesfrom one well over a 17 year period. Our initial analysis of the data has beensubsequently confirmed by Petroleum Insights Sàrl (“Petroleum Insights”),an independent oil and gas consulting firm with the assistance of Denver-basedMHA Petroleum Consultants LLC. Based on their analysis of pressure responsedata from the field during its 17 years of production history as well as onvolumetric calculations, Petroleum Insights has calculated a range of 18 to 25million barrels of oil in place. Petroleum Insights has also forecast 4.3 to 5.8million barrels of recoverable oil for 100% of the field. These figures are basedon a numerical full field simulation study assuming enhanced recovery throughconventional water-flooding. Subsequently, pressure data from the well hasindicated that the connected volumes are at or slightly above the high end ofthis range.

Based on Petroleum Insight’s positive evaluation, Candax is in the process ofdesigning a water-flooding and development well program to increase recoveryfrom the field and to enable categorization of all or part of these preliminaryfigures as proven and probable reserves under NI 51-101 standards. It isanticipated that this work will start in the second half of 2011, with the drillingof at least one new well on the Robbana structure. Prior to drilling,reprocessing of the existing 2D seismic data will be done, and if necessarythere will be an acquisition of 3D data. The first step is to resume production,however modest, from the Robbana-1 well in the second quarter of 2011.

Report on Operations

Robbana

DELIVERINGON OURPROPERTIES

Robbana – withsignificant oil in placethe development ofRobbana takes frontand centre position.

Early time oil-saturation map of five wells(three injectors, two producers) from fullfield simulation model.

Sucker-rod pump "Nodding Donkey"on Robbana-1 well.

The El Bibane 3 well, which had gone off-line in August 2009 with a brokentubing string was worked-over in August 2010 using the Ensco 85 jack-up rig.Despite finding the tubing to be broken in more than one place, production wasrestored via a new tubing string anchored above the irretrievable broken tubingand packer. At this stage, the field had essentially been off line for just over a year,and at start-up, it was clear that the production levels seen before the tubing brokein August 2009 were unlikely to resume immediately. By year end, production stillrequired artificial lift, with no sign of the well resuming natural flow. It appearsthat the gas-cap had recompressed during the shut-in period. It is increasinglyclear that the El Bibane field has robust remaining reserves. However, it isless clear how these can be extracted with the existing infrastructure. Giventhe under-performance of the two redevelopment wells, studies were initiatedto better understand the behaviour of the El Bibane 3 well and the El Bibanefield. This full-field numerical simulation will reconcile all data, history matchthe production data and provide scenario planning for the extraction of theremaining reserves. In parallel the existing seismic will be reprocessed andif deemed necessary new 3D seismic will be shot over the field in 2011.

A multi-well work-over and side-track program was performed byEzzaouia’s operator Maretap in 2010, continued into 2011. The initialresults of the program were mixed, with the Ezzaouia-5 side-trackencountering a swept zone. On the other hand, the work-overs havemanaged to successfully rectify various mechanical issues. The fullpotential of these work-overs has not yet been realized as the wellsrequire delicate pump optimization subsequent to the mechanicalwork-overs. These optimized production rates coupled with thefinalization of the Ezzaouia-2 side-track in 2011 will restore robustproduction levels to the Ezzaouia field. In parallel to the field operations,analysis of the Ezzaouia 3D seismic data has highlighted that improvementscould be achieved by reprocessing. This work is ongoing and is expected toprovide significant impetus for further infill well opportunities.

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The Ecumed operations team at theonshore Zarzis Central Processing Facilitywhich handles production from El Bibaneand Robbana.

Initial oil saturations in oil-rim from full-field simulation model of El Bibane.

After waiting 16 months, the Ulysse Rigarrived in the second quarter 2010 andperformed two side-tracks and three work-overs on the Ezzaouia field.

Ezzaouia

El Bibane

Ezzaouia is a mature field, with significantremaining reserves – accessible throughpatient and careful analysis. In collaborationwith our partners, studies are progressingthe future of this venerable field.

After a year of beingoff-line, El Bibane 3production wasrestarted inSeptember 2010.

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Belli and Al Manzahhave good potentialfor the redevelopmentof the shut-inreservoirs, aswell as excitingadditional potentialin unexploited levels.

Al Manzah operation prior to 2007 shut-in.

Belli and Al Manzah are non-producing fields. It is Candax’s firm belief thatthere is residual oil to be produced from both permits. Notwithstanding thatour early focus has been on Robbana, El Bibane and Ezzaouia, the technicaldata on Belli and Al Manzah has been thoroughly reviewed. Belli has potentialsimply from re-segregation of the reservoir fluids during its 13 year shut inperiod. Moreover there is considerable upside potential in the possibility of thehighly prolific fracture network being recharged via spontaneous imbibitionsfrom the porous matrix. Beyond this, the tight but porous matrix provides anadditional target for the future. The Boudabous formation was producing 250bopd when shut in (due to poor economics) in 1998 – we are confident that asidetrack on Belli 1 would provide profitable production in today’s economicclimate. Candax has initiated studies with ETAP via the jointly managedoperator Maretap to progress this.

Likewise Al Manzah was shut-in (subsequent to an unsuccessful work over)but has potential for small, but economically viable production. Al Manzahhas significant potential in deeper, undrilled formations that produce locallyon other permits.

Belli and Al Manzah

The Belli field site.

The Deep Triassic remains a significant element in the Candax portfolio. However,in 2010 attention has been focused on the near-term production gains that can beachieved from existing proven assets, with a view to underpinning the future ofCandax via sustainable revenues. Notwithstanding this, geological studies havereviewed, and reached very positive conclusions, on the potential of the DeepTriassic. Candax is evaluating various options for the future drilling of theseprospects, given the diverse challenges that such drilling will present and hasprogressed dialog with the various interested parties that would participate indrilling the Deep Triassic.

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In Madagascar, the first major milestone was achieved in June -obtaining a one year extension to the exploration permit. Subsequentto this, Candax progressed the necessary logistical and environmentalwork necessary as preparation for completing the agreed work programin 2011. The Environmental Impact Assessments (“EIAs”) andpreparative logistics were slower than initially anticipated, but EIAs havebeen successfully completed on both areas of interest – Ambilobe andAmpasindava. It is Candax’s firm intention to remain on this block, butwe are looking to reduce our working interest, in line with our corefocus on near-term production assets.

Candax’s exploration portfolio includes twovery prospective exploration plays – Block 1101in Madagascar covers 14,900 sq km in East Africa'smost prolific oil provinces with billion barrel potentialand in Tunisia our Deep Triassic covers over 130 sq kmwith seismic that suggests the prospect could be anequivalent to the TAGI formation, a prolific reservoirin Algeria, Libya and southern Tunisia.

Madagascar

Deep Triassic2D and 3D seismicperformed on theDeep Triassicidentified potential ofover 3 Tcf of gas.

Madagascar hasreported 30 billionbarrels of discoveredtar sands / heavy oiland lighter oils havealso been discoveredonshore.

Candax’s Madagascar Country Manager,Raharivola Danielson, leading the Ambilobepublic consultation in Antsohimbondrona,Madagascar.

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Candax’s board delivers the right mix of experience,competence and culture to define and guide thecurrent operational strategy and the growthstrategy for the years ahead.

Board of Directors

DELIVERINGWITH EXPERIENCE


M’hamed Ali BouleymanDirectorChairman, Ecumed Petroleum

Steven DrinkwaterDirector




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The following Management’s Discussion and Analysis (“MD&A”) for Candax Energy Inc. and its wholly-owned subsidiaries (“Candax” or the“Company”) should be read in conjunction with the accompanying audited consolidated financial statements and notes for the year endedDecember 31, 2010, as well as the MD&A and the audited consolidated financial statements for the year ended December 31, 2009. Readersshould also refer to a discussion of forward-looking statements contained at the end of this MD&A. Additional information relating to Candax,including its Annual Information Form for the year ended December 31, 2010 is available on SEDAR at www.sedar.com. This information ispresented as of March 31, 2011.

Company OverviewCandax is engaged in the exploration for and the acquisition, development and production of natural gas and crude oil. Its assets are located inTunisia and Madagascar. Candax also owns a 50% interest in Société d’Electricité d’El Bibane (“SEEB”), a Tunisian power generation company.

Foreign Exchange FluctuationsCandax operates primarily in a US dollar-based environment. The majority of the Company’s revenues and expenses are paid in US dollars,although Candax is also exposed to Canadian dollar, Euro, Pounds Sterling and Tunisian Dinar costs. However, being a Canadian companytrading on the TSX, Candax has elected to report its financial results in Canadian dollars. Accordingly, all foreign currency amounts presentedin Candax’s consolidated statements of operations and deficit and cash flows are converted to Canadian dollars for reporting purposes basedon the average Canadian to US dollar exchange rate prevailing during the reporting period. The US to Canadian dollar closing exchange rate onDecember, 2010 was $.9946 (2009 – $1.0510) and averaged $1.0131 (2009 – $1.0571) during the fourth quarter of 2010 and $1.0303 (2009 – $1.1420)for the year.

Capital Structure and DilutionAt December 31, 2009, Candax had 169,261,606 common shares outstanding. On March 31, 2010, Candax issued 144,444,444 commonshares at $0.09 per common share through a private placement and on May 27, 2010 Candax issued 75,666,666 common shares at $0.08per common share through the exercise of warrants to bring the total number of common shares outstanding at December 31, 2010 to389,372,716. On February 4, 2011, pursuant to the terms of the Debt Restructuring Plan, Candax issued 464,193,161 common shares ofthe Company to Geofinance in consideration for the cancellation of US $22 million of bank debt and US $1.0 million in bank fees, whichamounts were originally owing under the Company’s banking facility with the Bank of Scotland, and subsequently assigned to Geofinancepursuant to the Debt Restructuring Plan, and the conversion of a shareholder loan in the amount of EUR 2 million owing to Geofinance. Theshares were issued at $0.055 per share, which price represents the five-day weighted average trading price of Candax shares on the TSX,ended Thursday, February 3, 2011. The average EURCAD and USDCAD exchange rates over the same five-day period were used to determinethe number of shares to be issued. The new common shares issued represent 119% of the number of common shares of the Company issuedand outstanding just prior to the issuance, and as a result of this issuance, Candax now has 853,565,877 common shares outstanding as ofMarch 31, 2011, of which Geofinance holds 684,304,271 representing 80.17%.

At December 31, 2009, the Company did not have any warrants outstanding, however, in connection with the above-mentioned private placementthe Company issued 86,666,666 warrants on March 31, 2010. On May 27, 2010, 75,666,666 warrants were exercised at an exercise price of $0.08per share, leaving 11,000,000 warrants outstanding at December 31, 2010. The 11,000,000 warrants outstanding at December 31, 2010 expire onMarch 31, 2011.

At December 31, 2009, the Company had 10,700,000 stock options outstanding at an average exercise price of $0.78. During the year, 7,100,000options at an average exercise price of $0.80 expired and 3,050,000 options an average exercise price of $0.74 were forfeited, leaving 550,000options at an average exercise price of $0.79 outstanding at December 31, 2010. During the first quarter of 2011, 200,000 options at an averageexercise price of $0.97 per share expired leaving 350,000 options at an average exercise price of $0.72 per share outstanding at March 31, 2011.

Business Development ActivitiesCandax’s objective is to build a high-growth international portfolio of oil and gas assets.

Review of OperationsEL BIBANEEl Bibane is an oil and gas field located offshore Tunisia. Candax is the operator and holds a 73.8% working interest. The field re-developmentplan comprised three wells, El Bibane-3, 4 and 5. Oil production was constrained initially by capacity limitations in the export line, which, asa consequence of higher than expected water production, prevented simultaneous production from the El Bibane-3 and El Bibane-4 wells.Production has been further constrained by mechanical failures in these two wells identified in the course of a barge-based interventionprogram in September 2009. Remedial work programs to restore production were prepared. The first of these programs to restore productionfrom El Bibane-3 commenced in March 2010 and was completed in April 2010. The work-over successfully retrieved the parted tubing from thewell and it was determined that a packer failure and slippage of the entire down-hole production string had occurred which caused the originaltubing break. After repair, the well was initially restarted under gas-lift on April 12, 2010 with evidence of liquids coming to surface, but thiswas curtailed by surface valve problems. Once the surface valve was reopened the gas-lift pressure remained low and no further liquids wereseen on surface. Subsequent tests indicate that the replaced tubing failed, most likely at approximately the same depth as the original break.Although this result was disappointing, the reconnection work-over was considered to be a temporary fix to the existing tubing configuration,and it was recognized from the outset that further work would be required for a permanent solution, which work was planned for Phase 2of the well interventions.

MANAGEMENT‘S DISCUSSION AND ANALYSIS

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Phase 2 of the program for the El Bibane-3 well was designed during the second quarter of 2010 and the work started on July 24, 2010. Theoperation to remove the broken tubing from the El Bibane-3 well retrieved all but the last 200 metres of existing tubing and packer. The plan ofextending the tubing into the reservoir to limit the influx of water and running logging tools to better understand the reservoir was not possibledue to the inability to remove the entirety of the old tubing. The tubing was found in extremely poor condition and thus fishing operations weresuspended after considerable efforts. A casing integrity tool confirmed that the casing is in acceptable condition, and thus a new completion wasinstalled down to the top of the broken tubing. Fluid losses during fishing indicated that there was communication across the fish. The well wassuccessfully put back on production on Friday, September 10, 2010 using gas-lift with gas supplied from the El Bibane 5 well (gas-lift is beingoperated as a closed loop to minimize flaring, with all high-pressure gas being re-circulated). Oil production had stabilized at approximately 100to 150 barrels of oil per day with some 95% water-cut, production that is comparable to the overall volume of liquids that the well was producingprior to the well’s tubing failure in 2009. Prior to that tubing failure, the El Bibane-3 well was producing under natural flow and we expect thatthe well will revert to this behaviour. It is, however, not possible to predict exactly when this will occur.

Prior to making a decision on the design of the next phase of the El Bibane program, Candax has decided to conduct a full field simulationstudy and has contracted a French firm, BEICIP-Franlab, to complete such. The study is currently ongoing and is expected to be completed inMay 2011. The study will make recommendations as to the best alternatives to produce the remaining reserves of the El Bibane field. Candaxbelieves that the acquisition and processing of 3D seismic will be required to increase knowledge of the El Bibane field.

SEEBCandax has a 50% equity interest in Société d’Electricité d’El Bibane (“SEEB”), a Tunisian company which owns and operates a gas-fired 27MW single cycle electricity generation plant. Gas is supplied to SEEB primarily from El Bibane. The generating capacity of the power plantwas reduced by 50% from early May to December 2009 as a consequence of the failure of one of the two gas-fired turbines. The damagedturbine has been replaced though operations are presently constrained by the interruption of gas supply form the El Bibane field.

Due to the interruption in gas supply from the El Bibane field, SEEB has not produced any power since early January 2010. Due to theuncertainties as to the production of the El Bibane field, it is not possible for management to predict when SEEB will resume its operationsand what daily volume of gas will be delivered to SEEB.

As a result of reduced generating capacity, SEEB has been unable to meet its obligations under bank financing arrangements to makerepayments of principal and interest. As a consequence of the payment arrears, SEEB has received several default notices from the lendersunder its bank facility. As a consequence, the loans can be called by the lenders at anytime.

The Company and Caterpillar exercised joint control over the SEEB operations, however, during the fourth quarter of 2010, the banks, aslenders, started to impose tighter control over the day-to-day operations of SEEB. As a result of the actions by the banks, it was determinedthat the Company no longer exercised joint control over SEEB and consequently it was no longer appropriate to proportionately consolidateSEEB’s results. In accordance with Canadian GAAP, the investment in SEEB was deconsolidated and recognized at cost. As a result of thedeconsolidation, a charge of $1.1 million was expensed in the consolidated statements of operations and deficit. The Company reviewed thefinancial position of SEEB and determined that no amounts will be recoverable from this investment. The Company has no future financialobligation to SEEB or its lenders.

EZZAOUIAEzzaouia is primarily an on-shore oil field located in Tunisia producing small quantities of associated gas. The Ezzaouia field is operated byMaretap, a company owned by the interest holders in the field which include Candax and Entreprise Tunisienne d’Activités Pétrolières (“ETAP”),the Tunisian state-owned oil company. Candax owns a 31.4% working interest.

On July 22, 2010, the operator hooked up a side-track on the Ezzaouia-5 well. Open-hole log data showed the reservoir intervals to have lowerthan expected oil saturations and the production of the well was indeed disappointing, peaking at 70 barrels per day before going down to zero(100% water cut) after a few weeks. The Ezzaouia-5 well is currently shut-in and the partners are reviewing their options to determine the bestsolution to resume production from that well, which may involve perforating other layers.

The work-over of the Ezzaouia-1 well was completed on September 21, 2010. The well has shown disappointing production and a slicklineintervention is ongoing to install a blanking sleeve in the tubing and to test the completion to identify any possible leakage.

The Ulysse rig then moved to the sidetrack of the Ezzaouia-2 well. This sidetrack was temporarily suspended mid-October due to mechanicaldifficulties with the rig’s pump equipment. The equipment required to be able to continue with the sidetrack was received around March 20, 2011and the work has resumed.

While awaiting replacement parts, the rig was moved to the Ezzaouia-11 well location to remove the existing completion, mill the existingpacker, install a new packer and a new completion. Tie-in was completed mid-November. Because of lower than expected production, itwas decided to conduct a slickline operation to evaluate the formation, which is ongoing. The well will then be produced with swabbing.

After the tie-in was completed on the Ezzaouia-11, the rig moved to the Ezzaouia 9 well to retrieve the coiled tubing and run a new completion.The workover was completed in January 2011. Tests are ongoing to optimize the injection pressure to improve production.


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Candax is conducting a reinterpretation of the 3D seismic previously acquired to enhance its understanding of the various horizons, including theDeep Triassic, present in the Ezzaouia field. We expect that this reinterpretation of seismic will identify infill drilling locations and will optimizethe future work program to yield better results than the 2010 campaign.

ROBBANA FIELDRobbana is an on-shore oil field located in Tunisia. Candax is the operator and holds an 80% working interest. As a consequence of declining wellproductivity, production from the field was suspended in May 2009 pending drilling and completion of a planned sidetrack of the Robbana-1 well.MHA Petroleum Consultants LLC (“MHA”) and Petroleum Insights Sàrl (“Petroleum Insights”) have completed a full-field simulation study. Fromtheir analysis of the various pressure response data from the field during its 17 years production history Petroleum Insights and MHA haveidentified between 18 and 25 million bbls of oil in place and 4.3 to 5.8 million bbls of recoverable volumes, assuming a waterflooding programis implemented. Candax has initiated a workover, expected to be completed in April. The objectives of the workover are: (1) to take pressuremeasurements to further refine estimates of oil in place; (2) to obtain bottom hole samples for PVT analysis; and (3) to reestablish production.The data collected will enable Candax to better prepare for a probable stimulation workover of this well mid-year as well as for the anticipatedredevelopment of this field.

Based on the positive evaluation of Petroleum Insight’s study, the design of an optimal water-flooding program is also being initiated.

CHAAL PERMITChaal is an on-shore exploration permit located in central Tunisia approximately 50 kilometres west of the city of Sfax, covering an area of 1,200square kilometres.

An initial exploration well, Chaal-1, was drilled by Candax in 2006 but could not be tested due to formation damage caused by the heavy mudweights required to manage the high pressures encountered. Candax and its partners subsequently committed to drill a deviated sidetrack ofthe Chaal-1 well using managed pressure drilling to further evaluate the commerciality of the gas discovery and as a condition of securing anextension of the Chaal Permit to May 25, 2010.

In May 2010, Candax and its partners requested an extension of the permit but the Tunisian authorities have informed Candax that they werenot in a position to approve the extension. On September 24, 2010, the decision to cancel the permit was published in the official gazette ofthe Republic of Tunisia. The authorities are seeking penalties arising from the non-fulfillment of the committed work program. Discussionsare ongoing between Candax, its partners and the Tunisian authorities to determine the amount, if any, of the applicable penalties.

MADAGASCARBlock 1101 is an on-shore exploration permit located in northwest Madagascar and covers 14,900 square kilometres. The Company is theoperator with a 60% working interest.

Results from the initial geological fieldwork, geochemistry and gravity/magnetics confirmed the exploration potential of Block 1101, indicating upto 9,000 metres of sedimentary section beneath the block together with numerous oil shows.

In 2009, the Madagascar government approved a 12-month extension to the licence terms until July 30, 2010 and then in 2010 the licence wasfurther extended until July 30, 2011 within which time Candax has a commitment to drill an exploration well. To accommodate this extensionof the first exploration period the third exploration period will be reduced from two years to one year.

Work has been continuing to identify a drilling location. Two alternative sites have been identified and discussions are continuing to determinethe preferred location. The Environmental Impact Assessment is completed for one of the sites (the Ambilobe location) and is being finalized forthe other location (Ampasindava). The design of the drilling program (including civil works requirement to bring equipment on site) is ongoing.

Considering the size of the upcoming capex program and the risks associated with the prospects, Candax continues to explore farm-outdiscussions with several parties. There is no guarantee that these discussions will be successful.

Non-Producing AssetsThe Belli and Al Manzah permits as well as the Deep Triassic are being re-examined as part of a full review of the portfolio of assets.

Production from Al Manzah was characterized by a very energetic dynamic system with clear movement of fluid contacts. Having been shut-inthe field will have partially re-segregated, and it is likely that modest volumes of oil are readily accessible. However, the final (failed) workovermay have rendered the existing well useless. It is anticipated that, following further study, this field can resume production via new well. Thereservoir is shallow, at some 800 metres.

A study of the existing data on Belli coupled with a review of analogus fields and the literature by Petroleum Insights has indicated that thematrix STOIIP which is unlikely to have contributed to the production could be in the order of 50 MMbbls. It is conceivable, that in the timeframeof the shut-in (12+ years), that spontaneous recharging has occurred and that some of this oil may have migrated into the vugs/fractures. It isvirtually impossible with the existing data to estimate the probability of this occurring, however Petroleum Insights suggests that there is a 10%probability of this having occurred.

The Belli permit also has several promising exploration leads.


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Equity InvestmentOn March 31, 2010, the Company completed an investment agreement with Geofinance N.V., an international upstream oil and gas company(“Geofinance”). Under the terms of the agreement, Geofinance invested $13.0 million in the Company to purchase 144,444,444 units of theCompany at a price of $0.09 per unit, each unit comprising one common share and 0.6 of one common share purchase warrant for a total of86,666,666 warrants. Each whole warrant may be exercised for a period of one year from the date of the closing of the transaction at a priceequal to the current market price (calculated based on the weighted average trading price of the Company’s common shares for the fivetrading days immediately prior to the date of exercise).

On May 27, 2010, Geofinance exercised warrants to acquire 75,666,666 common shares of Candax at an exercise price of $0.08 per commonshare for total proceeds of $6.4 million.

As a consequence, at December 31, 2010, Candax had 389,372,716 common shares outstanding.

Bank Loan RestructuringOn March 31, 2010 Candax concluded an Amendment and Restatement Agreement with the Bank of Scotland by which the terms of theBorrowing Base Facility Agreement were amended and restated. The agreement provided for the extension of the maturity date of the facilityto June 30, 2014 and rescheduling of repayments while splitting outstanding amounts into two tranches; the Borrowing Base Amount and anExcess Tranche. Interest on the Borrowing Base Amount was calculated at US$ LIBOR plus 4% and on the Excess Tranche at US$ LIBOR plus9.5%. Under the terms of the Amendment and Restatement Agreement, a principal payment of US $8.0 million and restructuring fees ofUS $1.0 million were payable on December 31, 2010.

Debt Restructuring PlanOn February 4, 2011, the Company completed a two-step debt restructuring plan (the “Debt Restructuring Plan”). The key elements of the Debt

Restructuring Plan are as follows:

• On December 24, 2010, the Bank of Scotland, as sole lender under the Company’s US$45 million bank debt (the “Bank Debt”), assigned all

rights and obligations under the Bank Debt to Geofinance

• On February 4, 2011, Geofinance and Candax closed the restructuring of the Bank Debt and entered into a restructuring agreement (the

“Restructuring Agreement”). The main terms and conditions of the Restructuring Agreement are:

• In consideration for Geofinance converting US$22 million of the US$45 million Bank Debt into equity, Candax issued 396,590,242 shares

to Geofinance, at a price of $0.055 per share (representing the five-day weighted average market price at the time of the issuance);

• In consideration for Geofinance waiting the right to receive certain fees on December 31, 2010 in respect of the Bank Debt, Candax

issued 18,116,963 shares to Geofinance;

• Geofinance also converted the then existing EUR 2 million shareholder loan into 49,485,956 shares of Candax;

• Geofinance and Candax entered into a restructured and amended loan agreement for the remaining US$23 million debt (the “Amended

Loan Agreement”) and into a new US$10 million shareholder loan (the “Shareholder Loan”);

• The Amended Loan Agreement is split into: (1) a seven-year, US$15 million senior term loan (itself split between a US$5 million tranche

A priced at 4% and a US$10 million tranche B bearing interest at 4.5%, paid in kind), which will amortize over a five-year period starting

on January 31, 2013 and (2) an eight-year, US$8 million junior term loan, bearing interest at 6%, paid in kind (the Company will also pay

Geofinance a cash premium at maturity in order to provide a rate of return of 10% per annum to Geofinance). This junior term loan is

repayable at maturity;

• The Shareholder Loan has an eight-year maturity. The interest, payable in cash, is grid-based, with rates between 3.5% and 7.5%,

depending on the cumulated drawdown by Candax under the Shareholder Loan.

As detailed above, Geofinance received a total of 464,193,161 new shares. As at March 31, 2011, Candax had a total of 853,565,877 shares

outstanding (out of which 684,304,271 are owned by Geofinance).

In order to obtain approval for the Debt Restructuring Plan in advance of the December 31, 2010 payment owing to Bank of Scotland (as

discussed above under Bank Loan Restructuring), Candax relied on the financial hardship exemption provided by the TSX rules and Multilateral

Instrument 61-101. Reliance on this exemption automatically results in a TSX review for continued listing to confirm that Candax continues

to meet TSX listing requirements. The TSX Continued Listing Committee will convene to review the documents provided by Candax on

April 12, 2011.

Board of DirectorsJohn Cullen, Adrian Jackson and Michael Wood tendered their resignations as directors of the Company on March 31, 2010 and Thomas Rebilly,

Dr. Richard Norris and Stephen Drinkwater were appointed in their stead. Biographies of the new directors were disclosed in the Company’s

press release of March 10, 2010. At the Candax Annual General Meeting held on June 22, 2010, Adrian Loader, the former Chairman of Candax

did not stand for re-election and Benoit Debray was elected by shareholders as disclosed in the Company’s press release of June 29, 2010.

Murray Grant resigned from the board on November 25, 2010. M’hamed Ali Bouleymen was appointed in his stead on January 16, 2011.

Christopher Irwin remains on the board of directors of Candax.


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RevenueSales, net of royalties for the three months ended December 31, 2010, were $nil (2009 – $9.1 million) and for the year ended December 31, 2010

were $0.7 million (2009 – $28.1 million). During the fourth quarter of 2010, the Company did not sell any barrels of oil (2009 – 114,211 barrels sold

at an average price of US $68.48 per barrel) and on a year-to-date basis for 2010 the Company sold 9,454 barrels of oil at an average price of US

$67.87 per barrel (2009 – 423,882 barrels sold at an average price of US $52.25 per barrel). The reduction in sales in 2010 was primarily a result

of the El Bibane field being shut-in and of the natural decline in the production of the Ezzaouia field, which was not offset by the capital program

implemented in 2010, as discussed above.

As a result of the shut-in of the El Bibane field, no gas was delivered to SEEB during the year and consequently, no electricity sales were

included in sales, net of royalties for the three months and year ended December 31, 2010 compared with sales of $0.5 million and $2.6 million

for the same periods in 2009.

ProductionThe following table summarizes the quarterly net production (after royalty production) for 2010 and 2009:

Q1 Q2 Q3 Q4 Total

BBLS 2010 2009 2010 2009 2010 2009 2010 2009 2010 2009

Oil (bbls/day) 265 1,063 154 1,152 160 582 244 483 206 818

Gas (mmcf/day) – 3.5 – 2.9 – 1.2 – 2.3 – 2.5

BOEs/day 265 1,651 154 1,627 160 782 244 866 206 1,234

Production for the three months and year ended December 31, 2010 was lower than the same periods in 2009 due to reduced production from

the El Bibane and Ezzaouia fields as discussed earlier.

ReservesSummary of Gross and Net Reserves

Escalated Parameters, Forecast Prices and Costs

BOE Oil Natural GasGross Net Gross Net Gross Net

Reserves Category (Mboe) (Mboe) (Mbbl) (Mbbl) (MMcf) (MMcf)

Total Proved – All Categories 3.4 2.0 2.3 1.2 6,500 4.586

Probable – All Categories 5.1 2.4 4.5 2.0 3,675 2,411

Total Proved Plus Probable 8.5 4.4 6.8 3.2 10,175 6,997

The following table outlines Ryder Scott’s forecasted future prices for each of oil and natural gas. These forecasts form the basis for RyderScott’s evaluation of the Company’s reserves at December 31, 2010 as outlined above.

Crude Oil andNatural Gas Price Natural Gas Liquids

US$/Mcf $US/Bbl

2011 0.42 83.49

2012 0.54 83.49

2013 0.55 83.49

2014 0.56 85.46

2015 0.57 87.25

Average thereafter 0.60 95.85

Where amounts are expressed on a barrel of oil equivalent (boe) basis, natural gas volumes have been converted to barrels of oil equivalentat 6,000 cubic feet to one barrel of oil equivalent (6 mcf = 1 boe). This conversion ratio is the convention used in the oil and natural gas industryand is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalencyat the wellhead. The use of boe may be misleading, particularly if used in isolation.

Operating CostsOperating costs for the year and three months ended December 31, 2010, were $8.9 million and $1.0 million respectively, compared to$9.8 million and $3.6 million for the same periods in 2009. Operating costs were lower for the year ended December 31, 2010 compared to2009 due to reduced workover activity and the reversal of the year end accrual for the overlifting.


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Depletion, Depreciation and Amortization ExpenseFor the year and three months ended December 31, 2010, depletion, depreciation and amortization was $2.6 million and $0.6 million,respectively, (2009 – $45.6 million and $24.5 million, respectively). Depletion is calculated using the purchase price of the acquired assets,capital expenditures and proved reserves as at year-end. The significant decrease in 2010 over 2009 was due to reduced sales during 2010.

Asset ImpairmentAsset impairment for the year and three months ended December 31, 2010, was $nil and $nil respectively, (2009 – $20.6 million and$19.2 million, respectively). There was no impairment charge for 2010 as in 2009 writedowns were taken for Chaal in the amount of$10.2 million, Madagascar $3.5 million and an additional impairment charge of $4.6 million was taken after giving further considerationto potential impairment to the carrying value of its petroleum and natural gas properties by reference to a number of external factorsincluding the market capitalization of the Company and the proposed transaction with Geofinance NV.

Bad debt expenseBad debt expense for the year and three months ended December 31, 2010, was $1.1 million and $1.1 million respectively, (2009 – $nil and $nil,respectively). During 2010 the Company wrote off receivables from SEEB.

General and Administrative CostsFor the year and three months ended December 31, 2010, general and administrative costs were $10.2 million and $0.8 million, respectively,(2009 - $6.0 million and $1.7 million, respectively). The increase in costs over 2009 was primarily as a result of a provision made for governmentclaims, severance payments made to the previous management and the bank loan restructuring fee (which has subsequently been waived byGeofinance – see Note 23, Subsequent Event) in the Consolidated Financial Statements for the year ended December 31, 2010.

Loss on deconsolidation of joint venture interestFor the year and three months ended December 31, 2010, the loss on deconsolidation of joint venture interest was $1.1 million and $1.1 million,respectively, (2009 – $nil and $nil, respectively). The Company and Caterpillar exercised joint control over the SEEB operations, however, duringthe fourth quarter of 2010, the banks, as lenders, started to impose control over the day-to-day operations of SEEB. As a result of the actionsby the banks, it was determined that the Company no longer exercised joint control over SEEB and consequently it was no longer appropriateto proportionately consolidate SEEB’s results. In accordance with Canadian GAAP, the investment in SEEB was deconsolidated and recognizedat cost. The Company reviewed the financial position of SEEB and determined that no amounts will be recoverable from this investment. TheCompany has no future financial obligation to SEEB or its lenders.

Interest ExpenseInterest expense for the year and three months ended December 31, 2010 was $3.8 million and $1.1 million, respectively, (2009 – $4.5 millionand $1.4 million, respectively). Interest expense for 2010 was lower than the same periods in 2009 primarily as a result of the restructuringof the SEEB debt in June 2009 as well as a stronger Canadian dollar; the term loan is denominated in US dollars and the loans in SEEB aredenominated in US dollars and Euros.

Foreign ExchangeThe unrealized foreign exchange gain for the year and three months ended December 31, 2010 was $0.6 million and $nil respectively(2009 – losses of $2.6 million and $1.3 million, respectively). The unrealized foreign exchange gain for 2010 compared to losses in 2009 wasdue to a stronger Canadian dollar and the revaluation of the Euro-denominated loan in SEEB.

Related Party TransactionsDuring the year, the Company had gas sales to SEEB of $ nil (2009 – $0.4 million) and at December 31, 2010 the Company had a receivable fromSEEB in the amount of $0.9 million (2009 – $0.8 million). The receivable amount has been fully provided for.

At December 31, 2010, the Company had a related party term loan of US $44.5 million payable to its major shareholder, Geofinance. As describedin the debt restructuring plan above, in February 2011, Geofinance cancelled US $22 million of the related party term loan and rescheduled theJanuary 31, 2011 principal repayment to January 31, 2013, in exchange for common shares.

The Company had a loan from its major shareholder, Geofinance, in the amount of EUR 2.0 million at December 31, 2010. As described in thedebt restructuring plan above, in February 2011, Geofinance converted the shareholder loan into common shares.

During the year, the Company’s major shareholder charged one of the Company’s subsidiaries $0.4 million for services provided by itsemployees in accordance with the services agreement.


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Selected Quarterly Financial Data(in thousands of Canadian dollars except per share amounts)

Q1 Q2 Q3 Q4 Year

2010

Sales, net of royalties – – 696 – 696

Loss (3,614) (3,759) (13,900) (5,423) (26,696)

Loss per share – basic and diluted (0.02) (0.01) (0.04) (0.02) (0.08)

Total assets 89,063 98,202 80,875 68,200 68,200

Long-term financial liabilities 38,906 34,310 33,727 28,317 28,317

2009

Sales, net of royalties 8,288 8,548 2,181 9,123 28,140

Loss (13,943) (3,129) (3,681) (40,443) (61,196)

Loss per share – basic and diluted (0.08) (0.02) (0.02) (0.24) (0.36)

Total assets 193,256 159,745 136,576 95,518 95,518


2008

Sales, net of royalties 2,097 14,909 13,864 3,896 34,766

Net income (loss) (2,298) 2,820 1,573 (15,244) (13,149)

Net income (loss) per share – basic and diluted (0.01) 0.02 0.01 (0.09) (0.08)

Total assets 185,802 183,811 183,812 194,254 194,254


There were no sales during the first, second and fourth quarters of 2010 and only minimal sales during the third quarter of 2010 due to lowerproduction at El Bibane and Ezzaouia and the lifting process in Tunisia (where production from the El Bibane, Ezzaouia and Robbana fields areaggregated in 200,000 bbls tanks before being sold). Sales for the third quarter of 2009 were lower than each of the other three quarters of 2009primarily due to lower production at El Bibane. Sales for the first quarter of 2009 were higher than the fourth quarter of 2008 due to the timing ofthe liftings. Sales for the second quarter of 2008 were significantly higher than the first quarter of 2008 due to the start-up of production at the ElBibane field.

The loss for the fourth quarter of 2010 was lower than the loss for the third quarter of 2010 as during the third quarter of 2010 significant costswere incurred for the workover of the El Bibane field. The loss for the fourth quarter of 2009 was significantly higher than the current quartersin 2010 and the previous three quarters of 2009, primarily as a result of the recognition of asset impairments and related writedowns of$19.2 million.

The assets were lower in the fourth quarter of 2010 compared to the first three quarters of 2010 due primarily to the deconsolidation of the SEEBjoint venture assets as described earlier. The long-term liabilities for the fourth quarter of 2010 were lower than the previous three quarters of2010 due to the increase in the amount recorded in the current portion. The assets for the first three quarters of 2010 were lower than the firstthree quarters of 2009 due to the asset writedown. The long-term financial liabilities were lower in the fourth quarter of 2009 due to the strongerCanadian dollar against the US dollar which resulted in a lower liability for the US dollar-based term loan. The long-term financial liabilities forthe second quarter of 2009 were lower than the first quarter of 2009 and the fourth quarter of 2008 due to principal repayments made and theincrease in the amount recorded in the current portion. The increase in the long-term liabilities in the fourth quarter of 2008 over the first threequarters of 2008 was due to a drawdown in the credit facility.

Liquidity, Capital Resources and Capital ExpendituresCandax has historically relied on debt and equity financing to raise capital and expects to be able to continue to do so. Candax is also dependentupon sustained cash flow from its operations. A material fall in the oil price or prolonged curtailment of production risks could compromise theability of Candax to meet its obligations as they fall due.

As at December 31, 2010, Candax had a cash balance of $2.8 million (December 31, 2009 – $9.8 million) and accounts receivable of $0.3 million(December 31, 2009 – $4.1 million) compared to accounts payable and accrued liabilities of $9.0 million (December 31, 2009 – $17.9 million). Theworking capital deficit before financing at December 31, 2010 was $22.1 million.

As noted above, on March 31, 2010 Candax completed an investment agreement with Geofinance by which Geofinance contributed new equity of$13.0 million (net proceeds of $11.5 million) which funds were used to finance work programs and for general working capital purposes in 2010.In addition, on May 27, 2010, Geofinance invested a further $6.4 million on the exercise of warrants.


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In conjunction with the investment by Geofinance, on March 31, 2010, the Company concluded an Amendment and Restatement Agreementwith the Bank of Scotland by which the terms of the Borrowing Base Facility Agreement were amended and restated. The Agreement providedfor the extension of the final maturity date of the facility from December 31, 2012 to June 30, 2014 and rescheduling of principal repayments,while splitting outstanding amounts into two tranches; the borrowing base amount and an excess tranche. The new repayment schedulerequired the Company to make a principal repayment of US$8.0 million and a restructuring fee of US $1.0 million on December 31, 2010.

On May 19, 2010, the Company executed a EUR 2.0 million loan agreement with Geofinance. The shareholder loan was utilized for workingcapital requirements of Candax and utilization was subject to Geofinance’s approval. The loan bore interest at a rate of 3.5% per annum andmatured July 15, 2014. It was subordinated to the term loan provided by Bank of Scotland and repayments were governed by a subordinationagreement entered into by Candax, Geofinance and Bank of Scotland. This loan was cancelled on February 4, 2011 and converted to commonshares of Candax as part of the Debt Restructuring Plan discussed above.

As noted above in the “Debt Restructuring Plan” section, Candax completed a two-step restructuring in February 2011. As the Amended LoanAgreement has no principal amortization before January 31, 2013 and the interest payable under the Amended Loan Agreement are modest andlargely paid in kind and further that Geofinance has made a US$ 10 million shareholder loan available to Company, and finally that Candax hasminimal required capital investment obligations over the next 12 months, Candax expects to be able to continue as a going concern.

The Company is in discussions with several providers of capital. While there is no certainty these discussions will be successful, Candax woulduse these funds to accelerate its redevelopment programs, notably through the implementation of a water-flooding program on the Robbana field.

Candax’s work programs for 2011 include minimal already committed expenses. Depending on the outcome of the full-field simulationstudy being conducted by Beicip, Candax and its partners may acquire and interpret 3D seismic on El Bibane in Q3 and Q4 2011, at a costof approximately US $3.1 million (the final price may vary depending on the defined seismic area). On the Ezzaouia field, the sidetrack of theEzzaouia-2 well will be completed in Q2 2011. Maretap, the operator of the Ezzaouia field, will also improve and maintain its processing facilities.The total capex, net to the Company, on the Ezzaouia field, is expected to be approximately US $2.7 million. Candax is planning to hold a technicalcommittee meeting in April 2011 to initiate the reopening of the Belli field, which may occur at the end of Q3 or in Q4 2011.

Capital Management and SensitivitiesCandax manages its capital to ensure that the Company and its subsidiaries will be able to continue as a going concern while attempting tomaximize the return to shareholders through the optimization of debt and equity financing. The Board of Directors does not establish quantitativereturn on capital criteria for management, but rather relies on the expertise of the Company’s management to sustain future developmentof the Company. The capital structure consists of debt, cash and cash equivalents and shareholders’ equity excluding accumulated othercomprehensive income (loss). Candax monitors its capital through its net cash position calculated as cash less term loan debt. The Companymaintains this structure by managing working capital, capital spending programs and debt repayment terms. The Company raises capital,as necessary and the optimal balance between debt and equity may change over time.

Management reviews its capital management approach on an ongoing basis and believes that this approach, given the relative size of theCompany, is reasonable. There were no changes in the Company’s approach to capital management during the period ended December 31,2010 compared to the year ended December 31, 2009.

Sensitivity AnalysisBased on balances at December 31, 2010, the following shows the approximate impact on the Company’s earnings of a change in selectedkey variables. The impact is measured changing one variable at a time and may not necessarily be indicative of sensitivities on future results:

• Cash and cash equivalents include deposits which are at variable interest rates. Term debt under the related party term loan was alsoat variable interest rates. Sensitivity to a plus or minus 1% change in rates would affect the loss by $0.5 million for the year endedDecember 31, 2010.

• The Company does not hold significant balances or debt in currencies other than the US dollar to give rise to exposure to significantforeign exchange risk.

• The Company is exposed to changes in oil prices. Sensitivity to a plus or minus $1.00 change in the price of crude oil would affect theloss by $nil for the year ended December 31, 2010.

Commitments and ContingenciesUnder the provisions of the hydrocarbons law of Tunisia, 20% of the Company’s oil production must be sold to ETAP. Candax receives 90%of the export sales price achieved by ETAP on sale of such production.

Candax has provided a standby letter of credit in the amount of US $0.5 million in favour of Madagascar Ministry of Industry and Mines inaccordance with the terms of the production sharing agreement entered into in November 2006. The letter of credit will be released whenthe Company has satisfied the commitments as outlined in the agreement.


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The Company’s joint venture partners in the Chaal permit have submitted reports arising from their audit of the expenditures associated withthe initial Chaal exploration well. Amongst other matters, the reports assert claims for credit which, if sustained would result in the Companyincurring additional liability of US $0.4 million. The Company has received the reports and responded to the partners at the end of April 2010 buthave still not received a response from either partner. It is not anticipated that any additional material liability will be incurred and, accordinglyno amounts have been accrued for in this regard.

Critical Accounting EstimatesIn preparing financial statements management has to make estimates and assumptions that affect the reported amounts of assets, liabilities,revenues and expenses. Based on historical experience, current conditions and expert advice, management makes assumptions that arebelieved to be reasonable under the circumstances. These estimates and assumptions form the basis for judgments about the carrying value ofthe assets and liabilities and reported amounts for revenues and expenses. Different assumptions would result in different estimates and actualresults may differ materially from results based on these estimates. These estimates and assumptions are also affected by management’sapplication of accounting policies. Critical accounting policies and estimates are those that affect the consolidated financial statements materiallyand involve a significant level of judgment by management.

Going ConcernThe Company’s consolidated financial statements have been prepared on the basis that the Company will continue as a going concernand, as such, has sufficient assets and working capital to satisfy its financial obligations as they come due. In making this determination,management has made estimates of future revenues, and costs, and made assumptions on reserve status and the likelihood and timing foraccessing reserves. This process involves making various assumptions and judgments about each of the factors affecting the determinationof cash flows, production rates and fair values. Changes in any of these assumptions or judgments could result in significant difference fromthose used by management.

ReservesThe Company’s management makes estimates that relate to the future development costs associated with proved undeveloped reserves,reserve volumes, future production and revenues, and future costs associated with asset retirement obligations. The Company has its oiland gas reserves, future development costs and future cash flows from those reserves evaluated and reported on by Ryder Scott CompanyPetroleum Consultants, independent petroleum reserve engineering consultants. The estimation of these amounts is a subjective process,based on engineering data, forecasted prices and production levels and the timing of expenditures. All of these estimates are subject tonumerous uncertainties and various interpretations, and consequently will change over time to reflect updated information as it is received.

Petroleum and Natural Gas PropertiesCandax follows the full cost method of accounting, whereby all costs incurred in exploring for and developing oil and gas reserves arecapitalized. Such expenditures include geological and geophysical expenses, carrying charges for unproved properties, costs of drilling bothproductive and non-productive wells, gathering and production facilities and general and administrative costs directly related to explorationand development activities. Capitalized costs are accumulated on a country-by-country basis and are amortized and depleted using theunit-of-production method based upon estimated proved reserves. For those properties that are still in the development stage, relatedcosts are capitalized until either commercial production commences or it is determined that the invested amounts will never be recovered.

Natural gas reserves are converted to equivalent barrels of oil on the basis of their relative energy content (6 mcf equals 1 barrel). Costs directlyassociated with the acquisition and evaluation of unproved properties are initially excluded from the computation of depletion. These unprovedproperties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned, the cost of theproperty is added to all other capitalized costs subject to amortization and depletion.

Candax calculates a ceiling test whereby the net capitalized costs of properties cannot exceed discounted cash flows from proved and probablereserves. Cash flows are calculated based on third-party quoted forward prices and adjusted for the Company’s contracted prices and qualitydifferentials. If there is impairment, the magnitude of it would be calculated by comparing the carrying amount of property, plant and equipmentto the estimated net present value of future cash flows from proved plus risked probable reserves. A risk-free interest rate is used to arrive atthe net present value of the future cash flows. Any excess carrying value above the net present value of future cash flows would be recordedas a permanent impairment and charged as additional depletion expense in the consolidated statements of operations and deficit.

Sales of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recognized unless such adjustmentswould alter the rate of depletion and amortization by more than 20%.

Business RisksA comprehensive assessment of Candax’s business risks is set out in the 2010 Annual Information Form. There are a number of inherent risksassociated with oil and gas operations and development. Many of these risks are beyond the control of the Company. The following outlinessome of the principal risks and their potential impact on the Company:


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EXPLORATION, DEVELOPMENT AND PRODUCTION RISKSA portion of the current working capital of Candax will be expended on petroleum and natural gas exploration, exploitation and developmentactivities, which are high-risk ventures with uncertain prospects for success. Oil and gas exploration involves a high degree of risk and there isno assurance that expenditures made on future exploration activities by the Company will result in new discoveries of oil, condensate or naturalgas that are commercially viable or economically producible. Holders of securities of the Company must rely on the ability, expertise, judgment,discretion, integrity and good faith of management of the Company. It is difficult to project the costs of implementing any exploratory ordevelopmental drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encounteringvarious drilling conditions such as over-pressured zones and tools lost in the hole and changes in drilling plans and locations as a result ofprior exploratory wells or additional seismic data and interpretations thereof. Few properties that are explored are ultimately developed intonew reserves. In certain instances, the Company may be precluded from pursuing an exploration program or decide not to continue with anexploration program and such an occurrence may have a negative effect on the value of the securities of the Company.

Future oil exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficientnet revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment orrecovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost ofoperations, and various field operating conditions may adversely affect the production from successful wells. These conditions include: delaysin obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage ortransportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations cancontribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminatedand can be expected to adversely affect revenue and cash flow levels to varying degrees.

PETROLEUM AND NATURAL GAS RESERVESAll evaluations of future net revenues are before consideration of indirect costs such as administrative overhead, other miscellaneous expenses

and income taxes. The future net revenues may not be representative of the fair market value of the reserves. There is no assurance that the

forecast price and cost assumptions contained in the year end 2010 Ryder Scott Report will be attained and variances may be material. There

are numerous uncertainties inherent in estimating quantities of proved and probable reserves, including many factors beyond the control of

the Company. The reserves data and net present value of future cash flows set forth represent estimates only.

In general, estimates of economically recoverable petroleum and natural gas reserves and the future net revenues therefrom are based

upon a number of variable factors and assumptions, such as historical production from the properties, commodity prices, the assumed effects

of regulation by governmental agencies and future operating costs, each of which may vary considerably from actual results. Estimates of the

economically recoverable petroleum and natural gas reserves attributable to any particular group of properties, classification of such reserves

based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers

at different times, may vary substantially.

FLUCTUATION OF COMMODITY PRICESOil and natural gas are commodities whose prices are determined based on world demand, supply and other factors all of which are beyond

the control of the Company. Crude oil price is influenced by many factors, including the world economy, OPEC’s ability to adjust supply to

demand and political events. Where natural gas prices are not legislated to be linked to the price of oil, they are characterized more by regional

supply and demand considerations, as in North America, Europe, and the Middle East, where pipeline infrastructure between producing and

consuming nations plays a key role in price setting. More recently, LNG cargoes are setting the marginal cost for trans-ocean supply from

gas rich producing nations when pipeline delivery is impossible. Based on concerns for future oil supply and huge undeveloped gas reserves,

natural gas demand growth is transforming economics for both export and domestic markets around the world.

World prices for oil and natural gas have fluctuated widely in recent years. Future price fluctuations in world prices may continue and may

have a significant impact upon the projected revenue of the Company, the projected return from its existing and future reserves and the general

financial viability of the Company.

The oil and natural gas prices realized by the Company are affected by factors such as supply and demand, oil quality and transportation

adjustments. The Company expects to market its oil and natural gas production in a manner consistent with past practices. In the case

of natural gas, the Company has fixed rate sales contracts. The Company’s current natural gas production is subject to the provisions of the

Petroleum Law, which provides for sales into the Tunisian domestic market at rates less than those which would be realized in the international

market. While the Company sells the majority of its Tunisian oil to arms-length purchasers priced on a sale by sale basis at prevailing market

conditions, a portion of the oil produced by the Company is required to be sold domestically in Tunisia at rates less than those which would be

realized in the international market. There is no assurance that the price paid for the oil produced by the Company will remain at current levels.

A decrease in the price obtained for its oil may have a material adverse effect on the financial condition of the Company and its future operations.


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ASSET IMPAIRMENT RISKAs discussed above, future additional declines in commodity prices and uncertainty in the capital markets could lead to additional

impairments of the carrying value of the oil and gas assets held by the Company and thus may require a future significant charge to

earnings. Similarly, the Company may be required to record an asset impairment charge if the ongoing full-field simulation study on

El Bibane proved to be disappointing.

FOREIGN CURRENCY EXCHANGE RATESThe Company’s reporting currency is the Canadian dollar and the functional currency for the operating subsidiaries is the US dollar as all majorbusiness dealings are transacted in US dollars. The Company sells its oil production pursuant to marketing agreements that are denominatedin US dollars or indexed to the US dollar. Many of the operational and other expenses incurred by the Company are paid in US dollars or in localcurrency of the country where operations are performed. The Company funds the majority of its transactions using US dollar currency from itsUS dollar bank account held with a European bank. The related party term loan is also US dollar denominated. Management believes the foreignexchange risk derived from currency conversions is negligible and therefore does not hedge its foreign exchange risk. The reported assets andliabilities of the Company (including reserve information) are recorded in Canadian dollars. As a result, fluctuations in the US dollar against theCanadian dollar and each of these currencies against local currencies in jurisdictions where properties of the Company are located could resultin unanticipated and material fluctuations in the reported accounting financial results of the Company.

COMPETITIONA number of other oil and gas companies operate and are allowed to bid for exploration and production licenses and other services in countriesin Africa and the Middle East which are the focus of the business and operations of the Company, thereby providing competition to the Company.Larger companies may have access to greater resources than the Company, may be more successful in the recruitment and retention ofqualified employees and may conduct their own refining and petroleum marketing operations, which may give such companies a competitiveadvantage over the Company. Some of these companies have been conducting operations in Tunisia for considerably longer periods of time thanhas the Company and thus these companies may be more familiar with the political and business landscape in Tunisia than the Company. Inaddition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests.

ENVIRONMENTAL REGULATIONThe current and future operations of the Company that are conducted in Tunisia and Madagascar are subject to environmentalregulations enforced by the respective Governments. Should the Company initiate operations in other countries, such operationswill be subject to environmental legislation in such jurisdictions. Current environmental legislation generally provides for restrictionsand prohibitions on spills, releases or emissions of various substances produced in association with oil, condensate and natural gasoperations. In addition, certain types of operations may require the submission and approval of environmental impact assessments.The existing operations of the Company are subject to such environmental policies and legislation. Environmental legislation and policyis periodically amended. Such amendments may result in stricter standards and enforcement and in more stringent fines and penaltiesfor non-compliance. Environmental assessments of existing and proposed projects carry a heightened degree of responsibility for companiesand their directors, officers and employees. The costs of compliance associated with changes in environmental regulations could requiresignificant expenditures, and breaches of such regulations may result in the imposition of material fines and penalties. In an extremecase, such regulations may result in temporary or permanent suspension of production operations. There can be no assurance thatthese environmental costs or effects will not have a material adverse effect on the future financial condition or results of the operationsof the Company.

POLITICAL RISKSIn January 2011, the citizens of Tunisia initiated mass demonstrations against President Ben Ali and his government. These demonstrationsled to President Ben Ali leaving the country and to the resignation of the government then in place. New President, Prime Minister andgovernment have been appointed for the transition period, as per the constitution, with elections to be organized in July 2011. The newauthorities have been recognized by the international community. Certain people in the administration have left or changed positions,notably the head of the Direction Générale de l’Energie (Head of Energy Department within the secretary of energy), who has beenappointed head of ETAP, the national oil company.

The recent demonstrations in Tunisia have encouraged citizens of other countries to rise up against their respective governments andneighbouring Libya is currently in a state of unrest and as of the date of this MD&A certain NATO allies are undertaking airborne militaryaction to protect the citizens of Libya. Future unrest in any of the neighbouring countries could affect Tunisia.

In Madagascar, there has been instability in the administration, with several cabinet changes recently.

In addition to the political risks, the Company is also subject to the laws of the various levels of government in the countries, Tunisia andMadagascar, in which it conducts business. Such legislation may be changed from time to time in response to economic or political conditions,and the implementation of new legislation or modification of existing legislation affecting the oil and gas industry could change the Company’srevenues and/or costs and have a material adverse impact on the business, results of operations, financial condition and liquidity.


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In Tunisia and Madagascar, like in most countries, the government authorities have latitude in granting oil and gas permits, licences, andextensions thereof. The Company will be seeking extensions to its licences in the coming years and there is no guarantee that the governmentauthorities will grant them. A refusal to receive an extension would negatively impact the cash flows and asset value of the Company.

Recent Accounting PronouncementsThe Company will cease to prepare its consolidated financial statements in accordance with Canadian GAAP as set out in Part V of the CICAHandbook – Accounting (“Canadian GAAP”) for the periods beginning on January 1, 2011 when it will start to apply International FinancialReporting Standards as published by the International Accounting Standards Board. Consequently, future accounting changes to CanadianGAAP are not discussed in this MD&A as they will never be applied by the Company.

Convergence with International Financial Reporting Standards (“IFRS”)The Accounting Standards Board (“AcSB”) requires all Canadian publicly accountable entities to adopt IFRS for years beginning on or afterJanuary 1, 2011. Candax’s first annual filing will be for the year ended December 31, 2011 and its first filing under IFRS will be for the quarterending March 31, 2011 and will include IFRS comparative figures for the period ended March 31, 2010. Accordingly, Candax’s adoption date forIFRS is January 1, 2011, but its effective transition date (“Transition Date”) is January 1, 2010 in order to accommodate IFRS comparative figuresin Candax’s 2011 financial statements.

IFRS uses a conceptual framework similar to Canadian GAAP (“CGAAP”) however, there are significant differences in recognition, measurementand disclosure. Given the nature of Candax’s business and the make-up of its current balance sheet, IFRS could have an impact on its reportedfinancial statements. Candax’s implementation of IFRS will require the Company to make and disclose certain policy choices and increase theamount of disclosure necessary to fulfill its IFRS reporting obligations.

Adoption of IFRS is not expected to change the actual cash flows the Company generates or change its business activities. To the extent possible,Candax will make these choices with a view to providing meaningful information to stakeholders that is also comparable between industry peers.

The Company has commenced the development of an IFRS implementation plan to prepare for this transition, and is currently in the processof analyzing the key areas where changes to current accounting policies may be required. While an analysis will be required for all currentaccounting policies, the initial key areas of assessment will include:

• Evaluation of full-cost oil and gas accounting;• Accounting for exploration and evaluation expenditures;• Property, plant and equipment (measurement and valuation);• Provisions, including asset retirement obligations;• Stock-based compensation;• Foreign currency translation;• Accounting for joint ventures;• Accounting for income taxes; and• First-time adoption of International Financial Reporting Standards (IFRS 1)

As the analysis of each of the key areas progresses, other elements of the Company’s IFRS implementation plan will also be addressed,

including: the implication of changes to accounting policies and processes; financial statement note disclosures; internal controls; contractual

arrangements; and employee training.

The table below summarizes the expected timing of activities related to the Company’s transition to IFRS.


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Initial analysis of key areas for which changes to accounting policies may be required.

Detailed analysis of all relevant IFRS requirements and identification of areasrequiring accounting policy changes or those with accounting policy alternatives.

Assessment of first-time adoption (IFRS 1) requirements and alternatives.

Final determination of changes to accounting policies and choicesto be made with respect to first-time adoption alternatives.

Resolution of the accounting policy change implications on informationtechnology, internal controls and contractual arrangements.

Management and employee education and training.

Quantification of the Financial Statement impact of changes in accounting policies.

Completed

Completed

Completed

Completed

Completed

In process

Completed


The following provides a summary of the Company’s evaluation to date of potential changes to accounting policies in key areas based on thecurrent standards and guidance within IFRS. This is not intended to be a complete list of areas where the adoption of IFRS will require a changein accounting policies, but is intended to highlight the areas the Company has identified as having the most potential for a significant change. TheInternational Accounting Standards Board has a number of ongoing projects, the outcome of which may have an effect on the changes requiredto the Company’s accounting policies on adoption of IFRS. At the present time, however, the Company is not aware of any significant expectedchanges prior to its adoption of IFRS that would affect the summary provided below:

PROPERTY, PLANT & EQUIPMENT

Oil and gas propertiesUnder Canadian GAAP, the Company follows the CICA’s guideline on full cost accounting in which all costs directly associated with the acquisitionof, the exploration for, and the development of petroleum and natural gas reserves are capitalized on a country-by-country cost centre basis.Costs accumulated within each country cost centre are depleted using the unit-of-production method based on proved reserves. Full costaccounting is not permitted under IFRS. Under IFRS the Company will follow a modified successful efforts method of accounting, wherebyall costs incurred in exploring for and developing oil and gas reserves are capitalized on a field-by-field basis. Oil and gas properties includeacquisition costs and development costs related to producing wells, properties under development, and properties held for future development.IFRS 1 provides an exemption that allows oil and gas companies not to have to recalculate the valuation of each CGU based on the retroactiverestatement of its asset balances using the IFRS method acceptable under IFRS – “successful efforts” or modified successful efforts. TheCompany has elected to use this exemption.

Other plant & equipmentIFRS requires that the Company identify the different components of its fixed assets and record amortization based on the useful lives ofeach component. The Company has reviewed and analyzed the depreciation of its existing property, plant & equipment on this basis, and hasconcluded that there were some differences between IFRS and current depreciation policies. As such, an adjustment will be required on theopening Statement of Financial Position as at January 1, 2010. Subsequent additions to property, plant & equipment from the transition datewill be subject to componentization and amortized over their respective useful lives.

EXPLORATION AND EVALUATION COSTSUnder Canadian GAAP, pre-exploration costs related to properties held for future development are capitalized as incurred, including propertycarrying costs, drilling and other development costs. IFRS 6 segregates capital expenditures into different phases:

(i) Pre-exploration costs are costs incurred by the Company before it obtains the legal right to explore an area. Under Canadian GAAP

and full cost accounting, these costs are capitalized, whereas IFRS requires that these costs be expensed as incurred.

(ii) Exploration and evaluation costs are costs incurred after the pre-exploration phase but before technical feasibility and commercial viability

has been determined. Under Canadian GAAP and full cost accounting, these costs are capitalized. IFRS provides the Company with the

option of expensing these costs as incurred, or deferring these costs until technical feasibility and commercial viability has been

determined, at which point they are transferred to the development and production phase and allocated to specific projects.

(iii) Post-exploration development and production costs are costs incurred after technical feasibility and commercial viability have been

determined. Accounting for post-exploration costs are subject to the guidance provided in IAS 16: Property, Plant and Equipment.

On implementation of IFRS, there are no exploration and evaluation costs previously incurred to re-classify on the consolidated balance sheets.

IMPAIRMENT OF NON-FINANCIAL ASSETSUnder Canadian GAAP and full cost accounting, impairment tests for property, plant and equipment were performed based on the expectedrecoverability of costs in each geographic area through the full cost ceiling test. For purposes of impairment testing, IFRS requires that property,plant and equipment be segregated into cash generating units (“CGUs”) which are defined as the smallest identifiable group of assets thatgenerates sufficient cash inflows that are largely independent of the cash inflows from other assets or group of assets. Impairment calculationswill be performed at the CGU level using either proved or probable reserves.

Canadian GAAP does not permit the reversal of impairment losses. Under IFRS, if the conditions giving rise to impairment losses have reversed,impairment losses previously recorded would also be reversed.

The Company’s accounting policies related to impairment of non-financial assets will be changed to reflect these differences. However, the

Company does not expect that this change will have an immediate impact on the carrying value of its assets. The Company will perform

impairment assessments in accordance with IFRS at the transition date.

BUSINESS COMBINATIONSIFRS 1 provides an exemption that allows companies transitioning to IFRS not to restate business combinations completed prior to the date oftransition. The Company has elected to use this exemption and will not be restating the accounting for any acquisitions prior to January 1, 2010.


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ASSET RETIREMENT OBLIGATIONSThe Company has elected to use an IFRS 1 exemption to take a simplified approach to calculate and recognize the asset related to the asset

retirement obligation on the opening IFRS Statement of Financial Position. The provision for asset retirement obligation is calculated as at the

transition date in accordance with IAS 37: Provisions, Contingent Liabilities and Contingent Assets (“IAS 37”). To determine the amount of the

corresponding asset, the calculated provision under IAS 37 is discounted back to the date when the provision first arose, at which date the

corresponding asset is recognized. This asset is depreciated to its carrying amount as at the transition date. IFRS will require the Company

to re-measure its provision for asset retirement obligations on a quarterly basis using a pre-tax risk free rate adjusted for the risks specific to

the obligation or will adjust the cash flows to reflect the risk, which will result in some variability in both the carrying value of the liability and

corresponding asset, and associated expenses in profit or loss.

The above asset retirement obligations policy choices may result in a net increase or decrease in shareholders’ equity as at January 1, 2010.

SHARE-BASED PAYMENTSIn certain circumstances, IFRS requires a different measurement of stock-based compensation related to stock options than current

Canadian GAAP.

The Company will change its accounting policies related to share-based payments to include a forfeiture rate for stock options granted in the

calculation of the expense. The Company does not expect any significant impact on the consolidated financial statements at the transition date.

INCOME TAXESIn certain circumstances, IFRS contains different requirements related to recognition and measurement of future income taxes.

The Company is still evaluating the impact of these changes on the consolidated financial statements.

FOREIGN CURRENCYIFRS requires that the functional currency of the Company be determined separately, and the factors considered to determine functional

currency are somewhat different than current Canadian GAAP.

The Company does not expect any changes to its accounting policies related to foreign currency that would result in a significant change

to line items within its financial statements at the transition date.

CUMULATIVE TRANSLATION DIFFERENCESIFRS 1 permits cumulative translation gains and losses to be reset to zero at the transition date. The Company elected this exemption which

reduced the cumulative translation amount to zero at the transition date with a subsequent increase in the deficit.

Internal Control over Financial ReportingInternal controls over financial reporting are procedures designed to provide reasonable assurance that transactions are properly authorized,assets are safeguarded against unauthorized or improper use, and transactions are properly recorded and reported. A control system, no matterhow well designed and operated, can provide only reasonable, not absolute, assurance with respect to the reliability of financial reporting andfinancial statement preparation.

Evaluation of Disclosure Controls and Procedures and Internal Control over Financial ReportingThe Canadian Securities Administrators have issued National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and InterimFilings which requires public companies in Canada to submit annual and interim certificates relating to the design and effectiveness of thedisclosure controls and procedures that are in use at the company. Disclosure controls and procedures are designed to provide reasonableassurance that all relevant information is gathered and reported on a timely basis to senior management, including the Company’s ChiefExecutive Officer and Chief Financial Officer, to enable this information to be reviewed and discussed so that appropriate decisions can bemade regarding the timely public disclosure of the information.

As of December 31, 2010, management has evaluated the effectiveness of the design and the operating effectiveness of the disclosure controlsand procedures as defined by National Instrument 52-109. This evaluation was performed under the supervision of and with the participation ofthe Company’s Chief Executive Officer and Chief Financial Officer. Based on this evaluation, the Company’s Chief Executive Officer and ChiefFinancial Officer concluded that the design and operation of the disclosure controls and procedures were effective as of December 31, 2010.


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Internal Control over Financial ReportingNational Instrument 52-109 also requires public companies in Canada to submit an annual certificate relating to the design and operatingeffectiveness of internal control over financial reporting (“ICFR”). ICFR is designed to provide reasonable assurance regarding the reliability offinancial reporting and the preparation of financial statements for external purposes in accordance with Canadian generally accepted accountingprinciples. Management is responsible for establishing and maintaining ICFR and management, including the Company’s Chief Executive Officerand Chief Financial Officer, has evaluated the design and tested the effectiveness of the ICFR at December 31, 2010. Based on this evaluation,management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, has concluded that the design andoperating effectiveness of ICFR was effective as of December 31, 2010. The Company has continued to use the COSO framework to design itsICFR. Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements on a timely basis as suchsystems can only be designed to provide reasonable as opposed to absolute assurance. Also projections of any evaluation of the effectiveness ofICFR to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial ReportingNational Instrument 52-109 also requires public companies in Canada to disclose in their MD&A any change in ICFR during the most recentfiscal quarter that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting. There wereno changes in ICFR during the quarter ended December 31, 2010 that materially affected or are reasonably likely to materially affect theCorporation’s internal control over financial reporting.

Forward-Looking StatementsThis Management’s Discussion and Analysis includes “forward-looking statements”, within the meaning of applicable securities legislation,which are based on the opinions and estimates of Management and are subject to a variety of risks and uncertainties and other factors thatcould cause actual events or results to differ materially from those projected in the forward looking statements. Forward-looking statementsare often, but not always, identified by the use of words such as “seek”, “anticipate”, “budget”, “plan”, “continue”, “estimate”, “expect”, “forecast”,“may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and similar words suggesting futureoutcomes or statements regarding an outlook. Such risks and uncertainties include, but are not limited to, risks associated with the oil andgas industry (including operational risks in exploration development and production; delays or changes in plans with respect to exploration ordevelopment projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections in relation toproduction, costs and expenses; the uncertainty surrounding the ability of Candax. to obtain all permits, consents or authorizations required forits operations and activities; and health safety and environmental risks), the risk of commodity price and foreign exchange rate fluctuations, theability of Candax to fund the capital and operating expenses necessary to achieve the business objectives of Candax, the uncertainty associatedwith commercial negotiations and negotiating with foreign governments and risks associated with international business activities, as well asthose risks described in public disclosure documents filed by Candax. Due to the risks, uncertainties and assumptions inherent in forward-looking statements, prospective investors in securities of Candax should not place undue reliance on these forward-looking statements.Statements in relation to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based oncertain estimates and assumptions, that the reserves described can be profitably produced in the future.

Readers are cautioned that the foregoing lists of risks, uncertainties and other factors are not exhaustive. The forward-looking statementscontained in this MD&A are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements contained in this MD&A or in any other documents filed with Canadian securities regulatory authorities, whether as a resultof new information, future events or otherwise, except in accordance with applicable securities laws. The forward-looking statements containedin this MD&A are expressly qualified by this cautionary statement.


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The consolidated financial statements are the responsibility of, and have been prepared by, the management of Candax Energy Inc(the “Company”). To fulfill this responsibility, the Company maintains appropriate systems of internal control, policies and procedures. Thesesystems of internal control, policies and procedures help ensure that the Company’s reporting practices and accounting and administrativeprocedures provide reasonable assurance that the financial information is relevant, reliable, and accurate, and that assets are safeguardedand transactions are executed in accordance with proper authorization. These consolidated financial statements have been prepared inaccordance with Canadian generally accepted accounting principles. Where appropriate, these consolidated financial statements reflectestimates based on judgments of the management.

PricewaterhouseCoopers LLP, the independent auditors, have examined the consolidated financial statements of the Company. The independentauditors’ responsibility is to express a professional opinion on the fairness of the consolidated financial statements. The auditors’ report outlinesthe auditors’ opinion and the scope of their examination and their report follows.

The consolidated financial statements have also been reviewed by the Directors of Candax Energy Inc. and by its Audit Committee. The AuditCommittee is comprised of independent directors, and meets periodically during the year with the independent auditors and the management.The independent auditors have full and unrestricted access to the Audit Committee.

Dr. Richard Norris Matthieu MilandriPresident and Chief Executive Officer Chief Financial Officer

March 31, 2011

MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL REPORTING

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To the Shareholders of Candax Energy Inc.

We have audited the accompanying consolidated financial statements of Candax Energy Inc. and its subsidiaries, which comprise theconsolidated balance sheets as at December 31, 2010 and 2009 and the consolidated statements of operations and deficit, cash flowsand comprehensive loss for the years then ended, and the related notes including a summary of significant accounting policies.

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 Canadiangenerally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation offinancial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s responsibility

Our responsibility to express an opinion on these consolidated financial statements based on our audits. We conducted our audits inaccordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirementsand plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free frommaterial misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financialstatements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatementof the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevantto the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that areappropriate 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 madeby management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Candax Energy Inc. andits subsidiaries as at December 31, 2010 and 2009 and its results of operations and cash flows for the years then ended in accordance withCanadian generally accepted accounting principles.

PricewaterhouseCoopers, LLP

Chartered Accountants, Licensed Public Accountants

Toronto, Ontario

March 31, 2011

INDEPENDENT AUDITOR’S REPORT

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2010 2009AssetsCurrent

Cash and cash equivalents $ 2,770 $ 9,782

Accounts receivable 308 4,089

Inventory 3,570 137

Deposits, prepaids and other 388 505

7,036 14,513

Deferred financing fees – 163

Petroleum and natural gas properties 61,165 69,699

Property, plant and equipment (Note 6) – 11,143

$ 68,201 $ 95,518

LiabilitiesCurrent

Accounts payable and accrued liabilities $ 9,011 $ 17,886

Current portion of related party term loan (Note 9) 19,892 8,408

Current portion of long-term debt (Note 8) 199 210

Limited recourse long-term debt (Note 10) – 9,109

29,102 35,613

Related party term loan (Note 9) 24,368 37,738

Long-term debt (Note 8) 1,293 1,577

Shareholder loan (Note 11) 2,656 –

Asset retirement obligation (Note 12) 2,997 1,945

Future income tax liability (Note 13) 4,075 3,257

64,491 80,130

Shareholders’ EquityCapital stock (Note 14) 129,877 111,791

Contributed surplus (Note 14) 3,434 3,513

133,311 115,304

Accumulated other comprehensive loss (Note 18) (16,516) (13,527

Deficit (113,085) (86,389)

(129,601) (99,916)

3,710 15,388

$ 68,201 $ 95,518

Commitments (Note 20)

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

Approved on behalf of the Board of Directors

M’hamed Ali Bouleymen Benoit DebrayDirector Director

CONSOLIDATED BALANCE SHEETSAs at December 31 (in thousands of Canadian dollars)

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2010 2009Revenues

Sales, net of royalties $ 696 $ 28,140

Interest and other income 449 2,536

1,145 30,676

ExpensesOperating costs (Note15) 8,897 9,841

Depletion, depreciation and amortization 2,638 45,558

Asset impairment – 20,629

Bad debt expense 1,057 –

General and administrative 10,178 6,045

Loss on deconsolidation of joint venture interest (Note 7) 1,111 –

Interest 3,845 4,548

Foreign exchange (gain) loss (554) 2,558

Stock-based compensation (Note 14) (79) 277

Accretion on asset retirement obligation (Note 12) 173 137

27,266 89,593

Loss for the year before current and future income taxes (26,121) (58,917)

Current income tax expense (recovery) (85) 3,409

Future income tax expense (recovery) 660 (1,130)

575 2,279

Loss for the year $ (26,696) $ (61,196)

Deficit, beginning of year (86,389) (25,193)

Deficit, end of year $ (113,085) $ (86,389)

Loss per share – basic and diluted $ (0.08) $ (0.36)

Weighted average number of shares outstanding – basic and diluted 323,885,350 169,261,606


CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICITFor the year ended December 31 (in thousands of Canadian dollars except for per share amounts)

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2010 2009Operating ActivitiesLoss $ (26,696) $ (61,196)

Items not affecting cash

Stock-based compensation (79) 277

Depletion, depreciation and amortization 2,638 45,558

Asset impairment – 20,629

Bad debt expenses 1,057 –

Loss on deconsolidation of joint venture interest 1,111 –

Future income tax expense (recovery) 660 (1,130)

Accretion on asset retirement obligation 173 137

(21,136) 4,275

Net change in non-cash working capital (6,034) 7,456

(27,170) 11,731

Investing ActivitiesAdditions to petroleum and natural gas properties (3,317) (5,651)

Change in non-cash working capital from deconsolidation of joint venture interest 1,083

Additions to property plant and equipment – (1,688)

(2,234) (7,339)

Financing ActivitiesProceeds from shareholder loan (Note 11) 2,656 –

Issuance of common shares, net of share issue costs (Note 14) 18,086 –

Repayment of long-term debt (201) –

Deferred share issuance costs – (163)

Costs of share issuance – –

20,541 (163)

Foreign currency translation 1,851 (3,378)

Net increase (decrease) in cash and cash equivalents (7,012) 851

Cash and cash equivalents, beginning of year 9,782 8,931

Cash and cash equivalents, end of year $ 2,770 $ 9,782

Cash and cash equivalents are comprised of:

Cash $ 2,770 $ 9,782

Interest paid during the year $ 1,868 $ 3,006

Income taxes paid during the year $ 817 $ 1,097


CONSOLIDATED STATEMENTS OF CASH FLOWSFor the year ended December 31 (in thousands of Canadian dollars)

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2010 2009

Loss for the period $ (26,696) $ (61,196)

Other comprehensive loss:

Unrealized foreign exchange loss on translation of

self-sustaining foreign operations (2,989) (24,648)

Income taxes – –

Other comprehensive loss: (2,989) (24,648)

Comprehensive loss $ (29,685) $ (85,844)


CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSSFor the year ended December 31 (in thousands of Canadian dollars)

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1. DESCRIPTION OF BUSINESS AND NATURE OF OPERATIONS

Candax Energy Inc., (the “Company” or “Candax”), is incorporated under the laws of the province of Ontario. Candax is a Toronto-based oil andnatural gas company engaged in the exploration for, and the acquisition, development and production of, natural gas and crude oil. At present,all of the operating assets of the Company are located in Tunisia and Madagascar.

2 . SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of presentationThe consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”)and are presented in Canadian dollars unless otherwise stated.

These consolidated financial statements have been prepared on the basis that the Company is a going concern which contemplates therealization of its assets and the settlement of its liabilities in the normal course of operations. The ability of the Company to continueoperations is dependent upon maintaining sufficient oil production and to continue further exploration and development of its properties.

The significant accounting policies are summarized below:

ConsolidationThe consolidated financial statements include the accounts of Candax together with its wholly owned subsidiaries, Ecumed PetroleumGrombalia, Ltd., Ecumed Petroleum Tunisia, Ltd., Ecumed Petroleum Zarzis, Ltd. and Falcan Chaal Petroleum, Ltd. (known collectively asthe “Tunisian properties”), Candax Energy Limited (“CEL”), Candax Energy Services Limited (“CESL”) and the proportionate share of its 50%investment in Société d’Electricité d’El Bibane (“SEEB”) when such accounting is appropriate. All significant intercompany balances andtransactions have been eliminated.

Investment in Equity SecuritiesInvestment in equity securities is classified as an available-for-sale financial asset and recognized at cost as there is no quoted market pricein an active market.

Measurement uncertaintyManagement has made estimates and assumptions regarding certain assets, liabilities, contingent liabilities, revenues and expenses inthe preparation of the consolidated financial statements. Such estimates primarily relate to unsettled transactions and events as of the dateof the consolidated financial statements. Accordingly, actual results may differ from estimated amounts.

Depletion and amortization, and amounts used for ceiling test calculations are based on estimates of oil and natural gas reserves andcommodity prices, production expenses and capital costs required to develop and produce those reserves. The Company’s reserve estimatesare evaluated annually by Ryder-Scott Company Petroleum Consultants, independent petroleum reserve engineering consultants. By theirnature, estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the impact of differencesbetween actual and estimated amounts on the consolidated financial statements of future periods could be material.

The calculation of the asset retirement obligation includes estimates of the future costs to settle the asset retirement obligation, the timing ofthe cash flows to settle the obligation, and the future inflation rates. The impact of differences between actual and estimated costs, timing andinflation on the consolidated financial statements of future periods could be material.

Cash and cash equivalentsCash and cash equivalents comprise cash and short-term market investments with maturities of three months or less at the date of acquisition.

Petroleum and natural gas properties and related depletion and amortizationCandax follows the full cost method of accounting, whereby all costs incurred in exploring for and developing oil and gas reserves arecapitalized. Such expenditures include geological and geophysical expenses, carrying charges for unproved properties, costs of drillingboth productive and non-productive wells, gathering and production facilities and general and administrative costs directly related toexploration and development activities. Capitalized costs are accumulated on a country-by-country basis and are amortized and depletedusing the unit-of-production method based upon estimated proved reserves. For those properties that are still in the development stage,related costs are capitalized until either commercial production commences or it is determined that the invested amounts will neverbe recovered.

Natural gas reserves are converted to equivalent barrels of oil on the basis of their relative energy content (6 mcf equals 1 barrel). Costs directlyassociated with the acquisition and evaluation of unproved properties are initially excluded from the computation of depletion. These unprovedproperties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned, the cost of theproperty is added to all other capitalized costs subject to amortization and depletion.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTSFor the years ended December 31, 2010 and 2009(in thousands of Canadian dollars unless otherwise stated)

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The Company calculates a ceiling test whereby the net capitalized costs of properties cannot exceed discounted cash flows from proved andprobable reserves. Cash flows are calculated based on third-party quoted forward prices and adjusted for the Company’s contracted pricesand quality differentials. If there is an impairment, the magnitude would be calculated by comparing the carrying amount of property, plant andequipment to the estimated net present value of future cash flows from proved plus risked probable reserves. A risk-free interest rate is usedto arrive at the net present value of the future cash flows. Any excess carrying value above the net present value of future cash flows would berecorded as a permanent impairment and charged as additional depletion expense in the consolidated statements of operations and deficit.

Sales of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recognized unless such adjustmentswould alter the rate of depletion and amortization by more than 20%.

Foreign currency translationThe Tunisian subsidiaries are considered self-sustaining operations and exist in a business environment where the US dollar is their functionalcurrency. The financial statements of self-sustaining operations are translated into Canadian dollars from their functional currency using thecurrent rate method. Under this method, assets and liabilities are translated into Canadian dollars using the exchange rate in effect at theconsolidated balance sheet date. Revenues and expenses are translated into Canadian dollars at the average exchange rate for the period.All resulting exchange gains and losses are recorded in shareholders’ equity in the accumulated other comprehensive loss account.

CEL and CESL are considered integrated foreign operations and as such, their financial statements are translated using the temporal method.Under this method, monetary assets and liabilities denominated in foreign currency are translated into Canadian dollars at the exchange ratein effect at the consolidated balance sheet date and non-monetary assets and liabilities are translated into Canadian dollars at the exchange ratein effect on the transaction date. Revenues and expenses denominated in foreign currencies are translated into Canadian dollars at the averageexchange rate for the period. All resulting exchange gains and losses are recorded in the consolidated statements of operations and deficit.

Inventory valuationThe crude oil inventory and the material and supplies inventory are valued at the lower of cost and net realizable value.

Asset retirement obligationThe Company recognizes the fair value of an asset retirement obligation (“ARO”) in the period in which it is incurred when a reasonable estimateof fair value can be made. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carryingamount of the related asset. The capitalized amount is amortized to expense through depletion over the life of the asset. The liability amountis increased each reporting period due to the passage of time and the amount of this accretion is charged to earnings in the period. Revisions,if any, to the estimated timing of cash flows or to the original estimated undiscounted cost, if any, also result in an increase or decrease to theARO and the related asset. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded.Any difference between the actual costs incurred upon settlement of the ARO and the recorded liability is recognized as a gain or loss in theCompany’s earnings in the period in which the settlement occurs.

Stock-based compensation planThe Company has an incentive stock option plan which is described in Note 14. The Company accounts for its stock-based compensationplan using the fair value method. The fair value of stock options is determined on their grant date and recorded as compensation expense overthe period that the stock options vest, with a corresponding increase in contributed surplus. When stock options are exercised, the proceeds,together with the amount recorded in contributed surplus, are recorded in capital stock. The calculation of this expense is described in Note 14.

Financial InstrumentsFinancial instruments have been classified into one of the following five categories: held for-trading assets or liabilities, held-to-maturityinvestments, loans and receivables, available-for-sale financial assets or other financial liabilities. Held-for-trading financial instruments aremeasured at fair value and all gains and losses are included in consolidated statements of operations and deficit in the period in which theyarise. Available-for-sale financial instruments are measured at fair value with revaluation gains and losses included in accumulated othercomprehensive income until the instruments are derecognized or impaired. Loans and receivables, investments held-to-maturity and otherfinancial liabilities are measured at amortized cost.

The Company made the following classifications:

Cash and cash equivalents Held for tradingAccounts receivable Loans and receivables

Investment in equity securities Available-for-saleAccounts payable Other financial liabilities

Related party term loan Other financial liabilities

Long-term debt Other financial liabilities

Transaction costs are expensed for all financial instruments.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS(in thousands of Canadian dollars unless otherwise stated)

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Revenue RecognitionOil production from the El Bibane, Ezzaouia and Robbana fields is blended and accumulated in a storage tank owned by the Ezzaouia JV andperiodically lifted in marketable cargo sizes. The Tunisian state-owned company Entreprise Tunisienne d’Activités Pétrolières (“ETAP”), withrespect to its 55% participating interest in Ezzaouia field production and on behalf of the Government with respect to the royalty and domesticmarket delivery obligations, and the other partners in those fields acting in consortium have an agreement to lift in turn to optimize tankerlifting volumes. As a result of this practice, a short-term volumetric imbalance may arise through an “under/over” lift position. Overlift andunderlift are in effect a sale of oil at the point of lifting by the underlifter to the overlifter. As the criteria for revenue recognition is consideredto have been met, no deferred revenue is recorded. The Company treats an overlift as a purchase of oil at market price with an associatedliability also recorded; conversely, an underlift is treated as a sale of oil at market price with an associated asset also recorded.

Income taxesThe Company follows the liability method of accounting for income taxes. Under this method future tax liabilities and assets are recognized forthe estimated tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and theirrespective tax bases. Future tax liabilities and assets are measured using enacted tax rates. The effect on future tax liabilities and assets of achange in tax rates is recognized in the period that the change occurs.

Net income (loss) per common shareNet income (loss) per common share is calculated by dividing net income (loss) by the weighted average number of common shares

outstanding during the period. For the purposes of the weighted average number of common shares calculation, common shares are

determined to be outstanding from the date they are issued. Diluted income (loss) per common share is calculated using the treasury

stock method, which assumes that all outstanding stock option grants are exercised, if dilutive, and the assumed proceeds are used to

purchase the Company’s common shares at the average market price during the year.

3 . RECENT ACCOUNTING PRONOUNCEMENTS

The Company will cease to prepare its consolidated financial statements in accordance with Canadian GAAP as set out in Part V of the CICA

Handbook – Accounting (“Canadian GAAP”) for the periods beginning on January 1, 2011 when it will start to apply International Financial

Reporting Standards as published by the International Accounting Standards Board. Consequently, future accounting changes to Canadian

GAAP are not discussed in these consolidated financial statements as they will never be applied by the Company.

4 . EQUITY INVESTMENT

On March 31, 2010, the Company completed an investment agreement with Geofinance N.V., an international upstream oil and gas company(“Geofinance”). Under the terms of the agreement, Geofinance invested $13.0 million in the Company to purchase 144,444,444 units of theCompany at a price of $0.09 per unit, each unit comprising one common share and 0.6 of one common share purchase warrant for a totalof 86,666,666 warrants. Each whole warrant may be exercised for a period of one year from the date of the closing of the transaction at aprice equal to the current market price (calculated based on the weighted average trading price of the Company’s common shares for thefive trading days immediately prior to the date of exercise). If all of the warrants are exercised, Geofinance will own 231,111,110 commonshares in aggregate.

On May 27, 2010, Geofinance exercised warrants to acquire 75,666,666 common shares of the Company at an exercise price of $0.08 per

common share for total proceeds of $6.4 million.

5 . INVENTORY

2010 2009

Crude Oil $ 3,570 $ –

Materials and supplies – 137

$ 3,570 $ 137

During 2010, crude oil net inventory changes (opening less closing values) of $2.2 million (2009 – $0.9 million) were expensed which includes

a write-down to net realizable value of $2.2 million (2009 – $nil).

During 2010, materials and supplies inventory in the amount of $nil (2009 – $0.5 million) was written off due to obsolescence.


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6 CAPITAL ASSETS

Accumulated Carrying2010 Cost Amortization Value

Petroleum and natural gas properties $ 158,083 $ (96,918) $ 61,165

Property, plant and equipment – – –

$ 158,083 $ (96,918) $ 61,165

2009

Petroleum and natural gas properties $ 160,561 $ (90,862) $ 69,699

Property, plant and equipment 19,241 (8,098) 11,143

$ 179,802 $ (98,960) $ 80,842

As discussed in Note 7, the assets and liabilities of the Company’s joint venture interest in SEEB were deconsolidated and all the property,

plant and equipment belonged to SEEB. As a result, there is no balance in property, plant and equipment for 2010.

Exploration and AppraisalDuring 2009, the Company evaluated the carrying values of its interests in the Chaal Permit in Tunisia and in Block 1101 in Madagascar due

to the imminence of the expiry of the licence terms and the uncertainties concerning the nature and timing of drilling operations. Accordingly,

the Company concluded that it was appropriate to record impairment charges of $10.2 million and $3.5 million respectively in relation to those

interests. During 2010, any costs incurred on either of these two properties were expensed in the consolidated statements of operations and

deficit. Neither of these properties was included in the depletion calculation.

Producing AssetsIn addition to the annual ceiling test described in Note 2 and undertaken as at December 31, 2009, the Company gave further consideration to

potential impairment to the carrying value of its petroleum and natural gas properties by reference to a number of external factors including

the market capitalization of the Company and the proposed transaction with Geofinance NV. Having regard to such factors, the Company

recorded an additional impairment charge of $4.6 million. No impairment charge was recorded on the Company’s producing assets for 2010.

As at December 31, 2010:

• there are no amounts of capitalized head office general and administrative costs included in the cost of properties (2009 – $nil)

• the prices used in the ceiling test evaluation of the Company’s crude oil and natural gas reserves were:

Crude Oil andNatural Gas Price Natural Gas Liquids

US$/Mcf $US/Bbl

2011 0.42 83.49

2012 0.54 83.49

2013 0.55 83.49

2014 0.56 85.46

2015 0.57 87.25

Average thereafter 0.60 95.85

7. DECONSOLIDATION OF JOINT VENTURE INTEREST

The Company and Caterpillar Power Ventures International Ltd. (“Caterpillar”) each have a 50% interest in SEEB, a Tunisian power generationcompany. Late in the fourth quarter in 2010, the Company and Caterpillar exercised joint control over the operations, however, during the fourthquarter of 2010, the banks, as lenders, started to impose control over the day-to-day operations of SEEB. As the loans to the banks were indefault, the banks had the right to foreclose on the securities granted to them under the loan agreement, including, but not limited to, theshares owned by the Company and Caterpillar. As a result of the actions by the banks, management determined that the Company no longerexercised joint control over SEEB and consequently it was no longer appropriate to proportionately consolidate SEEB’s results. In accordancewith Canadian GAAP, the investment in SEEB was deconsolidated and recognized at cost. As a result of the deconsolidation, a charge of$1.1 million was expensed in the consolidated statements of operations and deficit. The Company reviewed the financial position of SEEB anddetermined that no amounts will be recoverable from this investment. The Company has no future financial obligation to SEEB or its lenders.


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8. LONG-TERM DEBT

In June 2009, the Company and Caterpillar agreed that Caterpillar’s US $5.0 million loan to SEEB should be converted from debt to equityand that new shares issued by SEEB should be allotted equally between the Company and Caterpillar. Upon the debt to equity conversion,the Company became unconditionally liable to Caterpillar for US $2.5 million which at December 31, 2010 amounted to US $1.5 million(December 31, 2009 – US $1.7 million), of which US $0.2 million is current. The Company’s payment obligations were unchanged.

9 . RELATED PARTY TERM LOAN

Rate ($000s)

December 31, December 31,2010 2009

Related party term loan – borrowing base amount LIBOR +4% $ 17,130 $ 46,146

Related party term loan – excess tranche amount LIBOR +9.5% 27,130 –

Less: current portion (19,892) (8,408)

$ 24,368 $ 37,738

On March 31, 2010, the Company concluded an Amendment and Restatement Agreement with the Bank of Scotland by which the terms ofthe Borrowing Base Facility Agreement were amended and restated. The Agreement provided for the extension of the final maturity date ofthe facility from December 31, 2012 to June 30, 2014 and the rescheduling of repayments while splitting outstanding amounts into two tranches;the borrowing base amount and an excess tranche. Bank restructuring fees of US $1.0 million were payable on December 31, 2010.

On December 24, 2010, the Bank of Scotland assigned all rights and obligations under the US $45 million term loan to Geofinance, the majorshareholder of the Company, under the same terms and conditions. Geofinance waived the principal repayment of US $8.0 million and the bankrestructuring fees of US $1.0 million, otherwise payable on December 31, 2010, until January 31, 2011.

As per Note 23, Subsequent Event, in February 2011, Geofinance cancelled US $22 million of bank debt and US $1.0 million in bank restructuringfees and rescheduled the January 31, 2011 principal repayment to January 31, 2013, in exchange for common shares.

For the year ended December 31, 2010, interest expense in the amount of $3.1 million (2009 – $3.2 million) has been recorded in the consolidatedstatements of operations and deficit.

10. LIMITED RECOURSE LONG-TERM DEBT

Rate


Limited recourse SEEB debtProject financing (US$ based) LIBOR +2.25% +2%

default margin* $ – $ 3,210Project financing (Euro based) ADB** +2.25% +2%

default margin* – 5,899– 9,109

Amounts due within one yearProject financing (US$ based) – (3,210)Project financing (Euro based) – (5,899)

– (9,109)$ – $ –

* The 2% default margin commenced August 2009 as principal payments were deferred and the loans were technically in default.

** African Development Bank Base Rate.


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Limited Recourse Long-Term Debt represents the Company’s share of the indebtedness of SEEB. The indebtedness comprises limited-recourse

bank financing, denominated in separate tranches of US dollars and Euros. Security for the bank financing is limited to the project assets,

the Company’s shareholding in SEEB and a fully collateralized non-performance guarantee from the Company of US $0.8 million.

As SEEB was in payment arrears, it received formal notice from the lending banks that it was in default and as such the loans could be called

by the lenders at anytime and therefore the entire amount of the limited-recourse loans was considered current during 2009.

As described in Note 7, during the fourth quarter of 2010, it was determined that the Company no longer exercised joint control over SEEB

and as a result the Company’s share of the limited recourse long-term debt was deconsolidated.

For the year ended December 31, 2010, interest expense in the amount of $0.6 million (2009 – $0.6 million) has been recorded in the consolidated

statements of operations and deficit.

11. SHAREHOLDER LOAN

On May 19, 2010, the Company executed a EUR 2.0 million loan agreement with Geofinance. The shareholder loan is available for working

capital requirements of the Company and utilization is subject to Geofinance’s approval. The loan bears interest at a rate of 3.5% per annum

and matures July 15, 2014. The shareholder loan is subordinated to the term loan and repayments are governed by a subordination agreement

entered into by the Company and Geofinance. During 2010, the entire amount of the EUR 2.0 million loan was drawn down and as at December

31, 2010 $2.7 million was outstanding. As per Note 23, Subsequent Event, in February 2011, Geofinance converted the shareholder loan into

common shares.

12. ASSET RETIREMENT OBLIGATION

2010 2009

Balance at January 1 $ 1,945 $ 1,449

Accretion expense 173 137

Foreign exchange (111) (210)

Revision in estimate 990 569

Balance at December 31 $ 2,997 $ 1,945

The total undiscounted amount of estimated cash flows required to settle the obligation is $9.5 million at December 31, 2010, which has been

discounted using a credit-adjusted risk-free rate of 9%. Most of these obligations are not expected to be paid until 2023 and beyond.

13. INCOME TAXES

The future tax liability of $4.1 million at December 31, 2010 (2009 – $3.3 million), relates to the difference in the unclaimed tax deductible costs

of capital assets in Tunisia and the related carrying value. The carrying value is based on the fair value of net assets acquired in the acquisition.

When the assets are amortized there will be an associated tax benefit for accounting purposes. The liability is based on consolidated accounting

values and any cash liability for income tax purposes is not triggered unless the underlying assets are sold. The approximate value of tax pools

available in Tunisia is $116.8 million (2009 – $123.4 million).

2010 2009

Loss before income taxes $ (26,121) $ (58,917)

Canadian corporate tax rate 31.00% 33.00%

Calculated income tax provisions (8,097) (19,443)

Effect on taxes from foreign tax rate differential (4,963) (10,016)

Expenses incurred with no recognized tax benefit 13,635 31,738

$ 575 $ 2,279


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Future income taxes have been provided for on the following temporary differences:

2010 2009

Capital assets $ 4,075 $ 3,257

Non-capital loss carryforwards (3,802) (2,912)

Valuation allowance 3,802 2,912

Net future tax liability $ 4,075 $ 3,257

At December 31, 2010, the Company had non-capital tax losses available to offset future income for tax purposes in Canada. The losses expire

in the years as noted:

2014 $ 404

2015 2,562

2026 1,107

2027 3,957

2028 1,981

2029 2,378

2030 2,819

$ 15,208

The Company has not recognized a future tax asset for Canadian non-capital losses carried forward. In addition, the Company has not

recognized a future tax asset of $20.9 million relating to the Tunisian properties. These assets have not been recognized since it is not, more

likely than not, that such assets will be utilized in the foreseeable future.

14. CAPITAL STOCK

Common sharesCandax is authorized to issue an unlimited number of common shares without par value. The Company’s issued and outstanding common

shares consist of the following:

Balance at December 31, 2008 and 2009 169,261,606 $ 111,791

Issuance of shares through private placement 144,444,444 13,000

Share issuance costs – (1,303)

Issuance of shares through the excercise of warrants 75,666,666 6,389

Balance at December 31, 2010 389,372,716 $ 129,877

As described in Note 4, on March 31, 2010, the Company issued 144,444,444 common shares at $0.09 per common share for gross proceeds

of $13.0 million and net proceeds of $11.7 million after deducting share issuance costs of $1.3 million. On May 27, 2010, Geofinance exercised

warrants to acquire 75,666,666 common shares of the Company at an exercise price of $0.08 per common share for total proceeds of $6.4

million. The common shares issued upon exercise of the warrants were subject to a hold period which expired on August 1, 2010.

Contributed Surplus

Balance at December 31, 2008 $ 3,237

Stock-based compensation 276


Stock-based compensation 71

Forfeiture of stock options (150)



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Stock Options

In April 2005, the Board of Directors established a share incentive plan to provide additional incentive to its directors, officers, employees

and consultants for their efforts on behalf of the Company in the conduct of its affairs. The maximum number of common shares reserved

for issuance under the share option plan comprising part of the share incentive plan may not exceed 10% of the number of common shares

outstanding. Under the terms of the plan, all options vest immediately, unless otherwise specified. All options granted under the plan expire

no later than the tenth anniversary of the grant date.

A summary of the status of the plans as of December 31, 2010 and 2009 and changes during the years ended on those dates are presented

as follows:

2010 2009Weighted WeightedAverage AverageExercise Number Exercise Number

Price of Options Price of Options

Outstanding – December 31, 2009 $ 0.78 10,700,000 $ 0.79 13,550,000

Transactions during the period:

Granted – – 0.20 50,000

Exercised – – – –

Expired 0.80 (7,100,000) – –

Forfeited 0.74 (3,050,000) 0.80 (2,900,000)

Outstanding – December 31, 2010 $ 0.79 550,000 $ 0.78 10,700,000

Weighted AverageRemaining Lifeon Outstanding

Price Options Options in OptionsRange Outstanding Months Exercisable

$0.20–$1.13 550,000 17 533,333

Using the fair value method, the compensation expense is amortized over the three-year vesting period of the options. For the year ended

December 31, 2010, the Company recorded a stock-based compensation recovery of $0.1 million (2009 – $0.3 million expense) relating to share

options. The portion of the fair value charge to be recognized in future periods is $ nil.

The fair value was estimated on the date of the grant using the Black-Scholes fair value option-pricing model and the following assumptions:

2010 2009

Expected volatility N/A 75%

Risk-free interest rate N/A 1.50%

Term N/A 5 years

Dividend yield N/A nil

15. OPERATING COSTS

EI Bibane workover costs $ 6,678 2,193

Production operating costs and other 2,219 7,648

8,897 9,841


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16. CAPITAL MANAGEMENT

The Company manages its capital to ensure that the Company and its subsidiaries will be able to continue as a going concern while attempting

to maximize the return to shareholders through the optimization of debt and equity financing. The Board of Directors does not establish

quantitative return on capital criteria for management, but rather relies on the expertise of the Company’s management to sustain future

development of the Company. The capital structure consists of debt, (Notes 8, 9 and 11), cash and cash equivalents and shareholders’ equity

excluding accumulated other comprehensive income (loss). Candax monitors its capital through its net cash position calculated as cash less

term loan debt. The Company maintains this structure by managing working capital, capital spending programs and debt repayment terms.

The Company raises capital, as necessary and the optimal balance between debt and equity may change over time. The Company is not subject

to externally imposed capital requirements.


Total debt $ 48,407 $ 57,042

Less: Cash and cash equivalents 2,770 9,782

Net debt 45,637 47,260

Shareholders’ equity 20,226 28,915

Total Capital $ 65,863 $ 76,175

Management reviews its capital management approach on an ongoing basis and believes that this approach, given the relative size of the

Company, is reasonable. There were no changes in the Company’s approach to capital management during the year ended December 31, 2010

compared to the year ended December 31, 2009.

17. FINANCIAL INSTRUMENTS

Fair Value EstimationFinancial instruments are classified as held for trading, loans and receivables, available-for-sales or other financial liabilities. Financial

instruments carried at fair value on the consolidated balance sheets are classified within a fair value hierarchy that prioritizes the inputs to

fair value measurements. The three levels of the fair value hierarchy are:

• Level 1 – Quoted prices in active markets for identical assets or liabilities;

• Level 2 – Inputs other than quoted prices that are observable for the asset or liability either directly or indirectly; and

• Level 3 – Inputs that are not based on observable market data.

The Company’s cash and cash equivalents are classified as Level 2.

The fair values of cash and cash equivalents, trade and other receivables and accounts payable and accrued liabilities approximate their

carrying values because of the short-term nature of these instruments.

The fair value of the Company’s debt obligations approximate their carrying value because substantially all of the total obligation is subject

to variable interest rates.

The Company’s risk exposures and the impact on the Company’s financial instruments are summarized below:

Credit riskCredit risk is the risk of loss associated with a counterparty’s inability to fulfil its payment obligations. The Company’s credit risk is primarily

attributable to accounts receivable. The Company has no significant concentration of credit risk arising from operations. Cash consists of funds

that have been invested with reputable financial institutions and management believes the risk of loss to be remote. Accounts receivable

consists of amounts due from partners and value added tax due from governments. Management believes that the credit risk with respect

to accounts receivable is low.


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Liquidity riskThe Company’s approach to managing liquidity risk is to ensure that it will have sufficient funds to meet liabilities as they come due. As at

December 31, 2010, the Company had a cash balance of $2.8 million (December 31, 2009 – $9.8 million) and accounts receivable of $0.3 million

(December 31, 2009 – $4.1 million) to settle current liabilities, excluding the current portion of limited recourse long-term debt, of $29.1 million

(December 31, 2009 – $26.5 million). At December 31, 2010 the Company had a working capital deficit of $22.1 million (December 31, 2009

– $21.1 million). The maturities of the Company’s accounts payable and accrued liabilities are within 1 year. As per Note 23, Subsequent Event,

Geofinance cancelled US $22 million of bank debt, US $1.0 million in bank fees and the EUR $2.0 million shareholder loan in February 2011

in exchange for common shares.

Interest rate riskThe Company has cash balances and interest-bearing debt. The Company’s current policy is to invest excess cash in highly rated short-term

deposits issued by a large European banking institution. The Company periodically monitors the investments it makes and is satisfied with the

credit ratings of its banks. Changes in interest rates will result in a change in the amount of interest charged on the Company’s term loan. Given

the current levels of interest rates and the economic conditions throughout the world, Management believes that the risk of material changes to

interest rate in the short to medium term is remote and therefore does not hedge its interest rate risk.

Foreign currency riskThe Company’s reporting currency is the Canadian dollar and the functional currency for the operating subsidiaries is the US dollar as all major

business dealings are transacted in US dollars. The Company funds the majority of its transactions using US dollar currency from its US dollar

bank account held with a European bank. The related party term loan debt is also US dollar denominated. Management does not hedge its

foreign exchange risk.

Price riskThe Company is exposed to price risk with respect to oil. The price of oil has been subject to substantial volatility in recent years. Future price

declines could cause continued reported accounting losses and future exploration to be uneconomical.

Sensitivity analysisBased on management’s knowledge and experience of the financial markets, the Company believes the following movements are “reasonably

possible” over a one year period:

• Cash and cash equivalents include deposits which are at variable interest rates. The related party term loan is also at variable interest

rates. Sensitivity to a plus or minus 1% change in rates would affect the loss by $0.5 million for the year ended December 31, 2010.

• The Company does not hold significant balances or debt in currencies other than the US dollar to give rise to exposure to significant foreign

exchange risk.

• The Company is exposed to changes in oil prices. Sensitivity to a plus or minus $1.00 change in the price of crude oil would affect the loss

by $nil for the year ended December 31, 2010.

18. ACCUMULATED OTHER COMPREHENSIVE LOSS

The balance in accumulated other comprehensive loss represents the cumulative amount of unrealized foreign exchange losses on translation

of self-sustaining foreign operations.

19. RELATED PARTY TRANSACTIONS

As described in Note 2, the Company has a 50% interest in SEEB. During the year the Company had gas sales to SEEB of $ nil (2009 – $0.4

million) and at December 31, 2010 the Company had a receivable from SEEB in the amount of $0.9 million (2009 – $0.8 million). The receivable

amount has been fully provided for.

As described in Note 9, the Company had a related party term loan of US $44.5 million payable to its major shareholder, Geofinance. As per

Note 23, Subsequent Event, in February 2011, Geofinance cancelled US $22 million of the related party term loan and rescheduled the

January 31, 2011 principal repayment to January 31, 2013, in exchange for common shares.

As described in Note 11, the Company had a loan from its major shareholder, Geofinance in the amount of EUR 2.0 million at December 31, 2010.

As per Note 23, Subsequent Event, in February 2011, Geofinance converted the shareholder loan into common shares.

During the year, the Company’s major shareholder charged one of the Company’s subsidiaries $0.4 million for services provided by its

employees in accordance with the services agreement.


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20. COMMITMENTS AND CONTINGENCIES

(a) Under the provisions of the hydrocarbon law of Tunisia, 20% of the Company’s oil production must be sold to ETAP. The Company receives90% of the export sales price achieved by ETAP on sale of such production.

(b) As at December 31, 2010, the Company had provided a standby letter of credit in the amount of US $0.5 million in favour of MadagascarMinistry of Industry and Mines in accordance with the terms of the production sharing agreement entered into in November 2006. Theletter of credit will be released when the Company has satisfied the commitments as outlined in the agreement.

(c) The Company’s joint venture partners in the Chaal permit have submitted reports arising from their audit of the expenditures associatedwith the initial Chaal exploration well. Amongst other matters, the reports assert claims for credit which, if sustained would result in theCompany incurring additional liability of US $0.4 million. The Company has received the reports and responded to the partners at theend of April 2010 but has still not received a response from either partner. It is not anticipated that any additional material liability willbe incurred and, accordingly no amounts have been accrued for in this regard.

21. SEGMENTED INFORMATION

ElectricityGeneration

Oil and Gas Operations Operations Total2010 2009 2010 2009 2010 2009

For the year ended

December 31

Sales (net of royalties) $ 656 $ 25,514 $ 40 $ 2,626 $ 696 $ 28,140Depletion, depreciationand amortization 2,175 44,917 463 641 2,638 45,558Interest expense 3,090 3,917 755 631 3,845 4,548Loss (25,577) (60,924) (1,119) (272) (26,696) (61,196)Capital assets as atDecember 31 61,165 69,699 – 11,143 61,165 80,842Total assets as atDecember 31 68,201 82,994 – 12,524 68,201 95,518

22. CHANGES IN NON-CASH WORKING CAPITAL

2010 2009Accounts receivable $ 3,781 $ 1,085Inventory (3,433) 4,328Deposits and prepaids 117 414Deferred financing fees 163 –Long-term receivable – 365Restricted investment – 945Accounts payable and accrued liabilities (6,662) 319

$ 6,034 $ 7,456

23. SUBSEQUENT EVENT

On February 4, 2011, pursuant to the terms of the Debt Restructuring Plan, Candax issued 464,193,161 common shares of the Companyto Geofinance in consideration for the cancellation of US $22 million of bank debt and US $1.0 million in bank fees, which amounts wereoriginally owing under the Company’s banking facility with the Bank of Scotland, and subsequently assigned to Geofinance pursuant to theDebt Restructuring Plan, and the conversion of a shareholder loan in the amount of EUR 2.0 million owing to Geofinance. The shares were issuedat $0.055 per share, which price represents the five-day weighted average trading price of the Company’s shares on the TSX February 3, 2011.The average EURCAD and USDCAD exchange rates over the same five-day period were used to determine the number of shares to be issued.The new common shares issued represent 119% of the number of common shares of the Company issued and outstanding just prior to theissuance, and as a result of this issuance, Candax now has 853,565,877 common shares outstanding of which Geofinance holds 684,304,271representing 80.17%.

As part of the Debt Restructuring Plan, the first principal repayment on the term loan is due January 31, 2013.

In addition, Geofinance and the Company entered into a Shareholder Loan Agreement which provides for borrowings up to US $10 millionat interest rates varying from 3.5% to 7.5% per annum.


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Candax Energy Inc. (“Candax”)is a Canadian independent, internationaloil and gas exploration, development andproduction company. The Company’s primaryobjective is to increase shareholder value bybuilding a sustainable, international upstreamcompany focused on opportunities in Africa andthe Middle East.

TABLE OF CONTENTS1 Achievements from 2010 and Objectives for 20112 Message to Our Shareholders4 Report on Operations8 Board of Directors9 Management’s Discussion and Analysis23 Forward-Looking Statements24 Management’s Responsibility for Financial Reporting25 Independent Auditor’s Report26 Consolidated Balance Sheets27 Consolidated Statements of Operations and Deficit28 Consolidated Statements of Cash Flows29 Consolidated Statements of Comprehensive Loss30 Notes to the Consolidated Financial Statements41 Corporate Information

New Logo Introduction

Candax is clearly a company reborn with a clean image and a new management team. The logo incorporates theindustry's universal colours for oil and gas of green and red with the flocks of green and red colour representingboth production and share growth. A bold and custom typeface was created to communicate a sense of confidenceand stability and ultimately represent the new image of Candax.

DIRECTORS AND OFFICERS



M’hamed Ali BouleymanDirector and Chairman,Ecumed Petroleum

Stephen DrinkwaterDirector



Matthieu MilandriChief Financial Officer

Pascal MirvilleChief Operating Officer andGeneral Manager, Tunisian OperationsEcumed Petroleum

Charlotte M. MayCorporate Secretary

BOARD SUB-COMMITTEEMEMBERSHIPAudit CommitteeM'hamed Ali Bouleymen – ChairmanBenoit DebrayChristopher O. Irwin

Compensation CommitteeBenoit DebrayStephen DrinkwaterThomas Rebilly

Governance CommitteeChristopher O. Irwin – ChairmanBenoit DebrayStephen DrinkwaterThomas Rebilly

Disclosure CommitteeBenoit Debray – ChairmanCharlotte M. MayMatthieu MilandriDr. Richard J. H. Norris

EXECUTIVE HEAD OFFICE130 Adelaide Street West, Suite 1010Toronto, Ontario, Canada M5H 3P5T + 416.368.9137F + 416.364.5400E [email protected]

TUNISIA OFFICEEcumed PetroleumRue du Lac WindermereLes Berges du Lac1053 Tunis, TunisiaT + 216.71.962.611F + 216.71.963.765

MADAGASCAR OFFICECandax Madagascar LtdImmeuble SANTALot III - 3è EtageAntanimenaAntananarivo 101MadagascarT + 261.20.22.265.58F + 261.20.22.265.81

INVESTOR RELATIONSCHF Investor Relations90 Adelaide Street West, 6th FloorToronto, Ontario, Canada M5H 3V9T + 416.868.1079F + 416.868.6198

AUDITORSPricewaterhouseCoopers LLPRoyal Trust Tower, TD Centre77 King Street WestSuite 3000, PO Box 82Toronto, Ontario, Canada M5K 1G8

BANKINGBank of MontrealMain Branch – 1 First Canadian Place100 King Street WestToronto, Ontario, Canada M5X 1A3

INDEPENDENT ENGINEERSRyder Scott Company1200, 530 - 8th Avenue SWCalgary, Alberta, Canada T2P 3S8

LEGAL COUNSELMcCarthy Tétrault LLPBox 48, Suite 5300Toronto Dominion Bank TowerToronto, Ontario, Canada M5K 1E6T + 416.362.1812F + 416.868.0673

McGrigors5 Old BaileyLondon EC4M 7BADX 227 London Chancery LaneTel: +44 (0)207 054 2500Fax: +44 (0)207 054 2501

TRANSFER AGENTEquity Financial Trust Company200 University Avenue, Suite 400Toronto, Ontario, Canada M5H 4H1T + 416.361.0152F + 416.361.0470E: [email protected]

TSX: CAXwww.candax.com

ANNUAL & SPECIAL MEETINGTuesday, June 28 at 10 am at theCorporation’s head office.130 Adelaide Street West, Suite 1010Toronto, Ontario, Canada M5H 3P5

Print date: May 24, 2011

Corporate Information

2010ANNUALREPORT

130 ADELAIDE STREET WEST, SUITE 1010TORONTO, ONTARIO, CANADA M5H 3P5T + 416.368.9137F + 416.364.5400E [email protected]

Candax Annual Report - 2010

Investor Relations

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