Full Year Results

Ithaca Energy

Iain McKendrick, CEO

[email protected]

+44 (0) 1224 650 261

Graham Forbes, CFO

[email protected]

+44 (0) 1224 652 151

Cenkos Securities plc

Jon Fitzpatrick

[email protected]

+44 (0) 207 397 8900

Neil McDonald

[email protected]

+44 (0) 131 220 6939

RBC Capital Markets

Tim Chapman

[email protected]

+44 (0) 207 653 4641

Matthew Coakes

[email protected]

+44 (0) 207 653 4871

FTI Consulting

Billy Clegg

[email protected]

+44 (0) 207 269 7157

Edward Westropp

[email protected]

+44 (0) 207 269 7230

Georgia Mann

[email protected]

+44 (0) 207 269 7212

2012 HIGHLIGHTS & POST YEAR END ACTIVITIES

Record annual earnings

·; 2012 cashflow from operations increased 50% to $90.3 million (2011: $60.2 million) - cashflow per share $0.35 (2011: $0.23)

·; 2012 net earnings increased 160% to $93.4 million (2011: $35.9 million) - earnings per share $0.36 (2011: $0.14)

·; 2012 average realized oil price of $112.76 / bbl (2011: $111.46 / bbl) including realized hedging gain in the year of $2.61 / bbl

·; Solid asset base with significant capital investment in the year reflecting total assets of $933.5 million (2011: $804.7 million)

·; Cash balance at year end of $31.4 million and $430 million senior borrowing base facility undrawn at the year end

·; UK tax allowances pool of $416 million at year end

·; Approximately 2 million barrels of 2013-14 oil production hedged at a weighted average price of around $109 / bbl (approximately 40% puts / 60% swaps)

Solid operational performance - executing the business plan

·; Export production increased 34% to approximately 5,862 barrels of oil equivalent per day ("boepd") (2011: 4,370 boepd), including production from the Cook and MacCulloch field interests being acquired from Noble Energy Capital Limited ("Noble"), effective January 1, 2012

·; 51.9 MMboe proved and probable ("2P") reserves at end-2012, as assessed by Sproule International Limited ("Sproule")

·; Sproule post-tax net 2P asset value ("NAV") of $1,045 million, up over 40%

·; Start-up of production from the Ithaca operated Athena field in May 2012, representing the third major development delivered by the Corporation

Greater Stella Area hub - moving ahead

·; Field Development Plan ("FDP") approval received from the Department of Energy and Climate Change ("DECC") for the Ithaca operated Stella and Harrier fields in April 2012

·; All major contracts executed in 2012 to deliver the start-up of production from the Greater Stella Area ("GSA") production hub in 2014

·; Fabrication of all the required subsea infrastructure that is to be installed by Technip is progressing according to plan

·; "FPF-1" floating production unit transferred to the Remontowa shipyard (Poland) in October 2012 for completion of the modification workscope by Petrofac

·; Ensco 100 drilling rig anticipated to arrive on location at the Stella field in Q2-2013

·; UK Small Field Allowance ("SFA") tax relief increased and its application extended in March 2012, resulting in both Stella and Harrier being eligible for the full $240 million field benefit in addition to Athena

·; Appraisal of the Hurricane discovery completed in September 2012 - hydrocarbons in two reservoir intervals identified and a successful drill stem test performed

Growing shareholder value via acquisitions and licence rounds

·; Intended acquisition of Valiant Petroleum plc ("Valiant") for a total enterprise value of approximately $459 million announced March 2013 - the Valiant Board is recommending approval of the offer to its shareholders and the transaction is scheduled to close mid-April 2013

·; Further broadening of the producing asset portfolio - agreements executed in October 2012 to acquire an additional 12.885% interest in the Cook field (acquisition completed February 2013) and a 14% interest in the MacCulloch field from Noble ("the Noble Assets")

·; Awarded two operated licences by the DECC in the 27th UK Licence Round

SUMMARY STATEMENT OF INCOME

(1) Average realized price before hedging

SUMMARY BALANCE SHEET

CORPORATE STRATEGY

Ithaca Energy Inc (the "Corporation" or "Ithaca" or the "Company") is an oil and gas operator focused on North Sea production, appraisal and development activities.

Ithaca's strategy is to grow shareholder value by building a highly profitable 25kboe/d North Sea oil and gas company. The execution of this plan is centred on:

·; Maximising production and cashflow from its existing assets

·; Delivering material growth by appraising and developing existing hydrocarbon discoveries

·; Continuing to increase and diversify the Company's portfolio and cashflows through acquisitions

CONSOLIDATION

The consolidated financial statements of the Corporation and the financial data contained in this management's discussion and analysis ("MD&A") are prepared in accordance with international financial reporting standards ("IFRS"). The consolidated financial statements include the accounts of Ithaca and its wholly-owned subsidiaries Ithaca Energy (Holdings) Limited ("Ithaca Holdings"), Ithaca Energy (UK) Limited ("Ithaca UK") and Ithaca Minerals North Sea Limited ("Ithaca Minerals") and its associates FPU Services Limited ("FPU") and FPF-1 Limited ("FPF-1").

All inter-company transactions and balances have been eliminated on consolidation. A significant portion of the Corporation's North Sea oil and gas activities are carried out jointly with others. The consolidated financial statements reflect only the Corporation's proportionate interest in such activities.

RESERVES

Solid 2P reserves base, with increasing proportion of reserves associated with producing assets

·; At 31 December 2012, the Corporation's 2P reserves were 51.9MMboe, as independently assessed by Sproule (including 1.4MMbbl from the yet to complete MacCulloch field acquisition)

·; 15.4MMboe of the Corporation's total 2P reserves are associated with producing assets, an increase of 83% on the end-2011 position. This increase is driven by start-up of the Athena field and the acquisition of the Noble Assets.

·; The end-2012 post-tax NAV of 2P reserves estimated by Sproule increased by over 40% to $1,045 million whilst pre-tax NAV of 2P reserves increased by approximately 33% to $1,442 million

·; The movement in 2P reserves between end-2011 and end-2012 is summarised in the table below. The Corporation has elected to relinquish the licence containing the Carna gas discovery following completion of a detailed technical and commercial evaluation since the additional equity and operatorship was transferred to the Corporation, for minimal consideration, by Centrica North Sea Gas Limited ("Centrica") in Q1-2012

* Opening reserves exclude the additional 16% equity in the Carna gas discovery transferred from Centrica during the year

PRODUCTION & OPERATIONS UPDATE

34% increase in annual production delivered in 2012, with the overall producing asset base enlarged to eight fields

2012 PRODUCTION

Ithaca's total net export production in 2012 was 5,862 boepd, representing an increase of approximately 34% on 2011 production (2011: 4,370boepd).

Production in the year was derived from the operated Athena, Beatrice, Jacky and Anglia fields and the non-operated Cook, Broom and Topaz fields. Total 2012 production also includes the contribution from the Noble Assets, the acquisition of which was announced in October 2012, effective 1 January 2012. The transfer of the Cook interest was completed in February 2013. The transfer of the MacCulloch interest is yet to complete and represents approximately 10% of total 2012 production.

The material increase in production delivered in 2012 was primarily attributable to the start-up of the Athena field in May 2012 and acquisition of the Noble Assets.

Planned maintenance shutdowns during the year, most notably on the Shell operated Anasuria floating production, storage and offloading vessel ("FPSO") that is the host facility for the Cook field, reduced overall net production performance by approximately 500 boepd.

As a result of the Athena field start-up and the acquisition of the Noble Assets, the Corporation has increased its producing asset base by a further three fields during the year, establishing a solid cash generative asset base of eight fields.

Q1-2013 production in line with forecast performance

Q1-2013 PRODUCTION UPDATE

With less than a week remaining in the quarter, Ithaca's total net export production in Q1-2013 is forecast to be in excess of 6,500 boepd. Production for the quarter was in the upper range of that anticipated by the Corporation as part of the annual 2013 guidance issued in January 2013 of 6,000 to 6,700 boepd. As anticipated, there was no contribution from the MacCulloch field in the quarter (MacCulloch representing approximately 5% of total forecast 2013 production).

DEVELOPMENTS UPDATE

Athena field achieves the core objectives of production diversification and cashflow generation, facilitating continued growth of the Company

ATHENA

Following completion of the BW Athena FPSO conversion and mobilisation operations by BW Offshore, start-up of production from the Athena field commenced in late May 2012. This represents the third major development delivered by the Corporation, further underlining the Corporation's ability to execute upon its business model of driving forward the monetisation of reserves identified following appraisal success.

Since the completion of post start-up commissioning activities, production from the field has been stable at a gross daily rate of between 10,000 and 11,000 bopd, 2,250 to 2,475 bopd net to Ithaca. Strong operational performance by the BW Athena has resulted in a vessel uptime in excess of 95% following the start-up period.

The field continues to produce "dry" oil, with nearly 3MMbbl having been produced from the field to date, 0.675MMbbl net to Ithaca.

Reservoir performance to date, including the continued production of dry oil, provides a positive signal for the longer term potential of the field. The timing of water breakthrough, along with the efficiency of the sweep of oil through the reservoir assisted by water injection, will be key to predicting the ultimate field production profile.

Athena's 2P reserves remain materially unchanged following completion of the end-2012 Sproule reserves evaluation, despite initial production rates from the field being lower than originally forecast. Taking into account the latest dynamic field data and actual oil production to date, Sproule's end-2012 2P reserves are within approximately 5% of that anticipated prior to start-up of the field. Total gross 2P remaining reserves at 31 December 2012 are estimated by Sproule to be 22.6 MMboe, 5.1MMboe net to Ithaca.

Clear hub strategy focused on driving significant value from the GSA infrastructure

GREATER STELLA AREA

The GSA strategy is driven by monetisation of 2P reserves of over 30MMboe net to Ithaca. The infrastructure that will be installed as part of the GSA development also presents the opportunity to create significant additional value from within the Corporation's portfolio and from third parties through the tie-back of the many undeveloped discoveries that lie in the catchment area of the GSA hub

Delivering First Hydrocarbons

Approval of the joint Stella and Harrier FDP was received from the DECC in April 2012. The development is centred on the tie-back of subsea wells to the FPF-1 floating production facility and the export of processed hydrocarbons to shore via nearby oil and gas transportation pipelines. To maximise initial oil and condensate production and fill the gas processing facilities on the FPF-1, four Stella wells are planned for the start-up of production from the hub. Further wells on Stella and Harrier, plus other potential targets, including Hurricane, will then be drilled post first hydrocarbons from Stella to maintain the gas processing facilities on plateau.

FPF-1 located in Remontowa yard in Gdansk, Poland, for completion of the modifications work programme

FPF-1 Modification Works

A lump sum incentivised contract for modification of the FPF-1 was awarded by the GSA co-venturers to Petrofac in October 2011. During 2012, the primary focus of the Petrofac work programme has been on completion of detailed design studies, award of the yard contract for the FPF-1 modification works and preparation and transfer of the vessel to the selected modifications yard.

Based on the results of the design studies completed in 2012, the decision was made by Petrofac to install new processing equipment on the vessel, rather than partially re-use the existing facilities. This is to ensure the delivery of a higher quality vessel; one that is capable of achieving the high operational uptime performance that is stipulated in the Duty Holder contract under which Petrofac will operate the FPF-1 once it is deployed in the field. Preparation of the vessel for completion of the modifications work was undertaken in Teeside, UK, with all the redundant processing equipment being removed from the main deck of the vessel.

Petrofac awarded the contract for completion of the FPF-1 modification works in 2012 to the Remontowa shipyard in Gdansk, Poland, which is located approximately 10 days towing time from the Stella field. The FPF-1 was moved to the yard in Q4-2012.

Work is currently ongoing on the vessel to prepare for its transfer to dry dock in Q2-2013 for the marine systems workscope to be completed, following which the new topsides processing plant will be installed on the main deck.

Arrival of Ensco 100 drilling rig now anticipated Q2-2013 due to delays in completion on current works being undertaken by another operator using the rig

Drilling Programme

A contract was signed with Ensco Offshore UK Limited ("Ensco") in November 2011 for use of the Ensco 100 heavy duty jack-up drilling rig on the Stella and Harrier development drilling campaign; 5 firm wells and 3 optional wells, providing flexibility in terms of the number of wells and sequence of drilling operations in the GSA.

A delay in completion of the work currently being undertaken by another North Sea operator using the Ensco 100 rig means that the rig is now anticipated to arrive on location at Stella in Q2-2013, rather than the previously indicated time of late Q1-2013. This delay, which is unrelated to the performance of the rig itself, is outside Ithaca's control and is a routine schedule risk associated with the commencement of any drilling campaign. Based on the commencement of the drilling campaign in Q2-2013, the four well programme on Stella (drill, complete and clean-up test) prior to start-up of production from the hub is anticipated to complete in the early part of Q2-2014.

Technip on schedule for execution of main subsea infrastructure works in 2013

Subsea Infrastructure Construction & Installation Activities

An Engineering, Procurement, Installation and Construction ("EPIC") contract was awarded to Technip in July 2012 for completion of the major subsea works required to deliver first hydrocarbons from the GSA hub. Engineering for the subsea infrastructure has been completed and the subsea facilities construction programme is progressing as planned and remains on target for the main installation works to be performed in 2013.

·; Manufacture of all the required 10-inch linepipe for the development has been completed and the application of coatings and delivery of the pipe to Technip's Evanton spool base in NE Scotland, for subsequent welding, is nearing completion.

·; Construction of all six subsea structures required to deliver first hydrocarbons are advancing well at Global Energy Group's Isleburn facilities at Invergordon and Nigg in NE Scotland. All the necessary valves that are to be fitted on the structures have been delivered on time.

·; All the flanges, fittings and pipework required for subsea structures have been manufactured on time and fabrication of the pipeline spools is ongoing.

·; Manufacture of the static umbilicals that will connect the drill centres to the FPF-1 and the flexible flowlines and risers are progressing to plan.

Small Field Allowance changes result in additional tax shelter available to Ithaca's Stella and Harrier field interests

Small Field Allowance Benefits

In March 2012 the UK Government announced it would be increasing and extending the application of the SFA, which shelters a portion of net cashflows from qualifying fields from the 32% Supplemental Charge. The size of fields that qualify for the full SFA was increased to include fields with Mid Case reserves under 6.25 million tonnes (approximately 45MMboe) and the tax allowance available to each field was doubled from approximately $120 million to $240 million.

The SFA changes have resulted in the Stella field being eligible for the full $240 million allowance and the Harrier allowance increasing from $120 million to the same amount. These allowances imply that Ithaca will shelter approximately $120 million of each fields' profits from the 32% Supplementary Charge.

Development Capital Expenditure

The Company's net share of remaining capital expenditure prior to first hydrocarbons from the GSA production hub is $385 million, which is unchanged from the estimate underpinning the amount announced in November 2012 and reflected in all subsequent guidance. This capital expenditure will be funded from the Corporation's existing financial resources.

In light of the delayed arrival of the Ensco 100 drilling rig, it is anticipated that some of the previously anticipated 2013 capital expenditure will now be incurred in 2014. Of the total capital expenditure of $385 million, approximately $300 million is currently forecast to be incurred in 2013, with the balance in the first half of 2014.

HURRICANE

Successful Hurricane appraisal well - the first potential bolt-on to the GSA hub

In September 2012, the Company successfully completed drilling of the Hurricane appraisal well in Block 29/10b, which lies within the GSA. The well was drilled using the WilHunter semi-submersible rig, with Applied Drilling Technologies International ("ADTI"), a subsidiary of Transocean, used to manage drilling operations under "turnkey" contract arrangements.

The well identified hydrocarbons in two reservoir intervals, the Eocene Rogaland sandstone and the Palaeocene Andrew reservoir; the latter being the main producing reservoir of the Stella field.

Pressure data and fluid samples were recovered from both intervals and a drill stem test ("DST") was performed on the Andrew reservoir. During the main DST flow period, lasting approximately 24 hours, the Andrew interval achieved an average gross flow rate of approximately 17 million standard cubic feet of gas per day ("MMscf/d") with associated condensate of 870 bopd (52° American Petroleum Institute "API" Gravity) from a half inch choke. A gross maximum flow rate of approximately 24 MMscf/d with associated condensate of 1,200 bopd from a 44/64-inch fixed choke was also achieved with the full production potential of the well being limited by surface equipment.

The appraisal well has been suspended for future potential use as a production well for the Andrew reservoir, with the capability of also being used for future production from the Rogaland reservoir. The integration of any future Hurricane infrastructure into the GSA hub can be accommodated within the existing design of the FPF-1 and subsea facilities.

A work programme, involving seismic reprocessing is ongoing to assess the ultimate recoverable volumes associated with each of Hurricane's reservoir intervals and assess the development options for the field. This work is being conducted in conjunction with a wider regional subsurface analysis that is focused on evaluating other future feeder fields for the hub. The results of the Hurricane work are anticipated later in 2013.

2012 CORPORATE ACTIVITIES

Further broadening of the producing asset portfolio - acquisition of additional Cook and MacCulloch field interests

Acquisition of Cook & MacCulloch Field Interests

In October 2012 the Company announced that it had entered into agreements with Noble Energy Capital Limited (a subsidiary of Noble Energy Inc., NYSE: NBL) to acquire two wholly owned UK subsidiary companies that hold its non-operated interests in two UK North Sea producing fields; a 12.885% interest in the Cook field and a 14% interest in the MacCulloch field (the "Noble assets").

The Cook field acquisition was completed in February 2013. Completion of the MacCulloch field acquisition is still subject to resolution of normal regulatory and joint venture approvals, including reaching agreement in respect of decommissioning costs and security.

27th License Round Success - new appraisal opportunities

27th License Round

In October 2012 Ithaca was awarded two operated licenses as part of the UK 27th Offshore Licence Round:

·; Block 29/5e is a joint venture between Ithaca (Operator, 54.66 %), Dyas UK Ltd. (25.34%) and Petrofac Energy Developments UK Ltd. (20%). The Block lies in the GSA, adjacent to Block 29/10b, which contains the Company's recently appraised Hurricane discovery. The joint venture has identified a target in Block 29/5d analogous to the appraised Hurricane Rogaland sand interval, known as "Twister".

·; Block 15/17b is a joint venture between Ithaca (Operator, 50%) and Premier Oil (UK) Ltd (50%). The block lies in the Outer Moray Firth basin and is close to the Ithaca operated Athena Field and Premier's license interests. The Block contains four undeveloped Jurassic oil discoveries, known as the "Piper Isles". The Block is adjacent to a number of producing oil fields, most notably Piper, Saltire, Iona and Chanter.

The work programme for both Blocks comprises the completion of technical (subsurface) studies, along with development concept screening analysis, to enable a decision to be made within two years of the formal award of each license on committing to the drilling of a well on each Block thereafter.

$430 million debt facility in place with seven international banks

Debt Facility

In July 2012 the Corporation executed a fully underwritten $430 million senior secured borrowing base facility agreement with BNP Paribas. The facility was subsequently syndicated by BNP Paribas, with the over subscribed syndication bringing in six other leading international banks.

Successful conclusion of Jacky J03 Court proceedings

J03 Court Case

In July 2012 the Commercial Court of the High Court of Justice ruled in favour of Ithaca in the dispute raised by its Jacky field partner, North Sea Energy (UK) Limited ("NSE"), concerning drilling of the "J03" development well in 2011.

INTENDED VALIANT PETROLEUM PLC ACQUISITION

Highly accretive acquisition - materially increasing production, reserves and cashflow

On March 1, 2013 it was announced that the Boards of Ithaca and of Valiant had reached agreement on the terms of a recommended acquisition (the "Acquisition") under which Ithaca will acquire all shares of Valiant. The total acquisition price is approximately $309 million, which equates to approximately £4.75 per Valiant share. The Company will also repay approximately $150 million of Valiant debt / working capital, implying a total enterprise value of approximately $459 million.

The Acquisition is to be financed by a low interest $350 million bridge loan and approximately $109 million from the issue of new Ithaca shares. The bridge facility, which has been agreed with BNP Paribas, the Bank of Nova Scotia and Bank of America Merrill Lynch, is available for 12 months, however, the intention is to fold the borrowing secured against the Valiant assets into an enlarged borrowing base facility during the year.

The Acquisition is anticipated to result in:

·; The establishment of Ithaca as a mid cap North Sea oil and gas operator, with 2P reserves of approximately 70MMboe, of which approximately 50% relates to currently producing assets;

·; A more than doubling of Ithaca's current forecast 2013 production to 14-16kboe/d (90% oil), rising to approximately 27kboe/d in 2015; and

·; Approximately a four fold increase in Ithaca's anticipated 2013 cash flow from operations to $400 million, rising to over $700 million in 2015.

The Acquisition is subject to approval by Valiant shareholders and certain regulatory approvals. The Valiant shareholders will meet on April 2, 2013 to vote on the Acquisition, with completion of the transaction anticipated to be mid-April 2013.

SELECTED ANNUAL INFORMATION

Financial Highlights

·; Revenue growth though increased production from asset acquisitions and the bringing of the Athena development on stream

·; Record Earnings per Share

·; Total assets increased mainly as a result of significant capital investment in Athena and the GSA development

·; Total non-current liabilities reduced through the improved tax position resulting from the recognition of the Small Fields Allowance in the Deferred Taxation calculation

2010 figures have been restated following the Corporation's election to present all acquisitions since the IFRS transition date as business combinations in accordance with IFRS 3(R). Refer to the Changes in Accounting Policies note below for more details.

2012 RESULTS OF OPERATIONS

REVENUE

Record annual revenue of $170.5 million

Revenue increased by $41.4 million in 2012 to $170.5 million (2011: $129.1 million). This was mainly driven by an increase in oil sales volumes, partially offset by a reduction in gas sales.

Oil sales volumes increased primarily due to the inclusion of sales from the Athena, Cook and Broom fields in 2012 (Cook and Broom acquired in H2-2011, with Athena commencing production in May 2012) offset by natural declines in the Beatrice and Jacky fields. Of the reported 5,862boepd production, 4,673 flows through the statement of income with the additional 1,189 boepd reflecting production from the acquisition of the Noble Assets.

The decrease in gas sales in 2012 compared to 2011 was due to a reduction in Anglia and Topaz gas volumes due to maintenance shutdowns, partially offset by the addition of Cook gas sales.

There was a small decrease in average realized oil prices from $111.46/bbl in 2011 to $110.15/bbl in 2012. The average Brent price for the year ended 2012 was $111.75/bbl compared to $110.86 for 2011. The Corporation's realized oil prices do not strictly follow the Brent price pattern given the various oil sales' contracts in place, with certain field sales sold at a discount or premium to Brent. This decrease in average realized oil price was nonetheless offset by a realized hedging gain of $2.61/bbl in 2012.

COST OF SALES

Cost of sales increased in 2012 to $135.0 million (2011: $95.1 million) due to increases in operating costs and depletion, depreciation and amortization ("DD&A"), partly offset by higher oil inventory.

Operating costs increased in the year to $85.5 million (2011: $48.3 million) primarily due to the inclusion of Athena, Cook and Broom operating costs in 2012 (Cook was acquired midway through Q3 2011 and Broom in Q4 2011, with Athena commencing production in Q2 2012) as well as the maturing Beatrice and Jacky fields incurring higher maintenance and servicing costs.

Operating costs increased to $49.74/boe in the year (2011: $41.32) mainly as a result of two factors. Cook operating costs were unusually high as a result of the field, at times, picking up almost 100% of the costs of the Shell operated Anasuria FPSO. The FPSO provides export and processing capability for three fields and the costs are shared according to oil throughput from each field. During the later part of 2012, both the other 2 fields suffered significant downtime for repair and hence Cook picked up all the operating costs severely impacting the operating cost/boe., Cook correspondingly benefits in periods where it suffers low uptime. The impact of picking up a higher share of the FPSO operating costs is expected to continue in the 1H of 2013 before returning to normal with the return of production from the other FPSO feeder fields. The second factor increasing operating expenditure during 2012 was the payment of incentive payments to the Athena operator and offshore Athena personnel in recognition of the exceptional uptime delivered by the vessel since the start of operations.

DD&A expense for the year increased to $56.2 million (2011: $31.4 million). This was primarily due to higher production volumes in 2012 with the addition of the Athena, Cook and Broom assets (Cook and Broom full year production 2012). The blended rate for the year has increased to $32.45/boe (2011: $26.57/boe).

As the below "Changes in Accounting Policies" section outlines, the adoption of IFRS and accounting for acquisitions as business combinations has led to increased DD&A rates, representing the majority of the rate increase. It should be noted that this increase in DD&A and hence Cost of Sales is offset by a credit in the Deferred Tax charged through the Income Statement.

In particular, DD&A rates on Cook have been significantly impacted as a result of accounting for acquisitions as business combinations with the DD&A rate increasing from $10.51/boe, excluding business combination uplift, to $27.85/boe including the business combination uplift.

An oil and gas inventory movement of $6.6 million was credited to cost of sales in 2012 (2011 charge of $15.4 million) primarily relating to the build up of stock levels on Cook, Athena and Broom. Movements in oil inventory arise due to differences between barrels produced and sold with production being recorded as a credit to movement in oil inventory through cost of sales until oil has been sold. In 2012 more barrels of oil were produced (1,506k bbls) than sold (1,427k bbls) with volumes accounting for $6.4 million of the movement. The remainder of the credit is due to the change in valuation of the opening inventory barrels, which are valued to reflect each field's relevant sales contract, such movements generally following the trend in Brent price, with some skewing due to the mix by field.

ADMINISTRATION & EXPLORATION & EVALUATION EXPENSES

Total administrative expenses decreased in the year to $5.2 million (2011: $6.0 million) primarily due to a reduction in share based payment expenses as a result of no options being granted during 2011, therefore reduced amortisation expense throughout 2012, and the only options in 2012 being granted at the end of the year. This was coupled with a modest decrease in general and administrative ("G&A") expenses despite the overall growth in activity of the business.

Exploration and evaluation expenses of $4.3 million were recorded in the year (2011: $0.8 million) primarily due to the decision not to pursue the development of the Carna discovery after detailed commercial and technical review.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

A foreign exchange gain of $1.0 million was recorded in 2012 (2011: $0.8 million loss). The majority of the Corporation's revenue is US dollar driven while operating expenditures are primarily incurred in British pounds. As such, general volatility in the USD:GBP exchange rate is the driver behind the foreign exchange gains and losses, particularly on the revaluation of the GBP bank accounts (USD:GBP at January 1, 2012: 1.55. USD:GBP at December 31, 2012: 1.62 with fluctuation between 1.55 and 1.63 during the year). This volatility was partially offset by foreign exchange hedges as described in the "Risks and Uncertainties" section below.

The Corporation recorded a $6.7 million gain on financial instruments for the year ended December 31, 2012 (2011: $3.4 million loss). The gain was predominantly due to a $2.5 million increase in value of oil swaps and put options and a $3.7 million realized gain on commodity hedges, along with a $1.8 million gain on the revaluation of other instruments, partially offset by a $1.3 million loss on revaluation of contingent consideration liabilities, triggered by FDP approval, relating to the acquisition of the Stella field and Challenger Minerals (North Sea) Limited ("CMNSL").

TAXATION

No UK tax anticipated to be payable in the mid-term

A deferred tax credit of $64.2 million was recognized in the year ended December 31, 2012 (2011: $1.2 million charge). This credit is a product of adjustments to the tax charge primarily relating to the available SFA, UK Ring Fence Expenditure Supplement, share based payments, and relief claimed for the reinvestment of disposal proceeds relating to the sale of assets to Petrofac GSA Limited and Dyas UK Limited. As noted in the Cost Of Sales section the deferred tax credit is increased by the use of accounting for acquisitions as business combinations.

As a result of the above factors, profit after tax increased to $93.4 million (2011: $35.9 million).

No tax is expected to be paid in the mid-term future relating to upstream oil and gas activities as a result of the $416 million tax losses available to the Corporation.

CAPITAL INVESTMENTS

Ithaca aims to maximise shareholder value through delivery of a lower risk growth strategy. This growth strategy focuses on investment in undeveloped discoveries as well as producing assets, which in turn allows the Company to maximise cashflow and production from its existing assets, and continue to grow and diversify the cashflow base via acquisitions.

Capital expenditure on D&P assets in 2012 of $139.4 million was primarily focused on: execution of the GSA development, with the main areas of expenditure being on the manufacture and fabrication of subsea infrastructure and preparation for the FPF-1 vessel upgrade and modification works (as described above); and, bringing the Athena development to first oil, with expenditure incurred on subsea installations for the arrival of the FPSO.

Capital expenditure on E&E assets in 2012 was $38.2 million with spending primarily focused on drilling of the Hurricane appraisal and work completed for the 27th licensing round.

LIQUIDITY AND CAPITAL RESOURCES

Significant investment in development projects

As at December 31, 2012, Ithaca had working capital of $15.6 million including a free cash balance of $31.4 million. Available cash has been, and is currently, invested in money market deposit accounts with BNP Paribas. Management has received confirmation from the financial institution that these funds are available on demand.

Cash and cash equivalents decreased significantly due to the capital investment made during 2012, primarily on the GSA development, with more investment, and therefore, payables outstanding, in the fourth quarter of 2012. This was partially offset by a rise in trade and other receivables as a result of the higher oil price at December 31, 2012 compared to December 31, 2011 as well as higher production volumes (average of 5,462 boed Q4 2012 compared to 3,774 boed Q4 2011).

A significant proportion of Ithaca's accounts receivable balance is with customers in the oil and gas industry and is subject to normal joint venture/ industry credit risks. The Corporation assesses partners' credit worthiness before entering into joint venture agreements. The Corporation regularly monitors all customer receivable balances outstanding in excess of 90 days. As at December 31, 2012 substantially all of the accounts receivable is current, being defined as less than 90 days. In the past, the Corporation has not experienced credit loss in the collection of accounts receivable.

At December 31, 2012, Ithaca had unused credit facilities totalling $430 million (2011: $140 million). Drawdown of this facility has commenced in Q1 2013.

During the year ended December 31, 2012 there was a cash outflow from operating, investing and financing activities of approximately $65 million (2011 outflow of $100.0 million).

Cashflow from operations

Cash generated from operating activities was $90.3 million primarily due to cash generated from Athena, Beatrice, Jacky, Anglia, Cook and Broom operations, augmented in 2012 primarily due to the start up of Athena.

Cashflow from financing activities

Cash generated from financing activities was $15.0 million primarily due to the release of restricted cash balances in Q4 2012.

Cashflow from investing activities

Cash used in investing activities was $145.5 million primarily due to capital expenditure on the GSA, including modification of the FPF-1, subsea design and fabrication works, appraisal well drilling on the Hurricane field and completion activities on the Athena field prior to first production in May 2012.

The Corporation continues to be fully funded, with more than sufficient financial resources to cover the anticipated level of development capital expenditure commitments and to continue the pursuit of additional asset acquisition opportunities and exploration and appraisal activities on existing and newly acquired licenses through its existing cash balance, forecast cashflow from operations and its debt facility. No unusual trends or fluctuations are expected outside the ordinary course of business.

COMMITMENTS

The engineering financial commitments relate to pre-development committed capital expenditure on the Stella and Harrier fields, as well as ongoing capital and operating expenditure on existing producing fields. Rig commitments reflect rig hire costs committed in relation to the anticipated Stella wells. As stated above, these commitments are expected to be funded through the Corporation's existing cash balance, forecast cashflow from operations and its undrawn debt facility.

OUTSTANDING SHARE INFORMATION

The Corporation's common shares are traded on the Toronto Stock Exchange ("TSX") in Canada under the symbol "IAE" and on the Alternative Investment Market ("AIM") in the United Kingdom under the symbol "IAE".

As at December 31, 2012 Ithaca had 259,920,003 common shares outstanding along with 20,347,964 options outstanding to employees and directors to acquire common shares.

In January 2012, the Corporation's Board of Directors granted 400,000 options at a weighted average exercise price of C$2.31. In October 2012, the Board of Directors approved the grant of 5,645,000 options at a price of C$1.99. Each of the options granted may be exercised over a period of four years from the grant date. One third of the options will vest at the end of each of the first, second and third years from the effective date of grant.

As at March 25, 2013, Ithaca had 259,920,003 common shares outstanding along with 20,347,964 options outstanding to employees and directors to acquire common shares.

(1) Represents the close price on the TSX on December 31, 2012. US$:CAD$ at par on December 31, 2012

Q4-2012 FINANCIAL RESULTS

Oil and gas sales revenue decreased from $54.9 million in Q4 2011 to $52.6 million in Q4 2012. The decrease was predominantly due to a smaller Cook lifting in Q4 2012 compared to Q4 2011 as well as an expected decline in Beatrice and Jacky revenues. Gas volumes were also down on the same period in 2011 due to shutdowns (particularly Anglia) as well as anticipated natural decline, however, this was partly offset by an increase in realised gas prices ($43.50/boe 2012 compared to $41.11/boe 2011).

Cost of sales increased to $52.0 million in Q4 2012 (Q4 2011: $48.8 million). The main driver behind the increase was the rise in operating costs due to the inclusion of Athena operating expenditure (2011: nil), significant Cook operating expenditure in the quarter as well as the maturing Beatrice and Jacky fields incurring higher maintenance and servicing costs. In addition, DD&A increased primarily due to addition of Athena plus a small increase in rates with the blended rate for the quarter increasing to $34.00/bbl compared to $33.30/bbl in Q4 2011. These rises were however partially offset by a reduced movement in inventory balance of $1.4 million (Q4 2011: $22.6 million - particularly high due to the initial Cook stock movement post acquisition in Q3 2011).

SUMMARY OF 2012 QUARTERLY RESULTS

The most significant factors to have affected the Corporation's results during the above quarters are fluctuation in underlying commodity prices and movement in production volumes. The Corporation has utilized forward sales contracts and foreign exchange contracts to take advantage of higher commodity prices while reducing the exposure to price volatility. These contracts can cause volatility in profit after tax as a result of unrealized gains and losses due to movements in the oil price and USD : GBP exchange rate.

Each of the quarters from Q4 2010 to Q3 2011 was restated following the Corporation's election to present all acquisitions since the IFRS transition date as business combinations in accordance with IFRS 3(R). Refer to the "Changes in Accounting Policies" below for more details.

FINANCIAL INSTRUMENTS

All financial instruments are initially measured in the balance sheet at fair value. Subsequent measurement of the financial instruments is based on their classification. The Corporation has classified each financial instrument into one of these categories: held-for-trading, held-to-maturity investments, loans and receivables, or other financial liabilities. Loans and receivables, held-to-maturity investments and other financial liabilities are measured at amortized cost using the effective interest rate method. For all financial assets and financial liabilities that are not classified as held-for-trading, the transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability are adjusted to the fair value initially recognized for that financial instrument. These costs are expensed using the effective interest rate method and are recorded within interest expense. Held-for-trading financial assets are measured at fair value and changes in fair value are recognized in net income.

All derivative instruments are recorded in the balance sheet at fair value unless they qualify for the expected purchase, sale and usage exemption. All changes in their fair value are recorded in income unless cash flow hedge accounting is used, in which case changes in fair value are recorded in other comprehensive income until the hedged transaction is recognized in net earnings.

The Corporation has classified its cash and cash equivalents, restricted cash, derivatives, commodity hedge and long term liability as held-for-trading, which are measured at fair value with changes being recognized in net income. Accounts receivable are classified as loans and receivables; operating bank loans, accounts payable and accrued liabilities are classified as other liabilities, all of which are measured at amortized cost. The classification of all financial instruments is the same at inception and at December 31, 2012.

The table below presents the total gain / (loss) on financial instruments that has been disclosed through the statement of comprehensive income.

The following table summarises the commodity hedges entered into during the year.

Post year end, further hedges (~50% puts / ~50% swaps) were entered into for approximately 1 million barrels of production for the period to September 2014 at a weighted average price of $108/bbl.

An option, exercisable in late April 2013, to swap ~ 1 million bbls of production over the next 12 months at over $107/bbl was also taken out post year end.

The table below summarises the foreign exchange financial instruments in place during 2012.

Post year end, further instruments were entered into to hedge £4 million operating costs per month for the period January 2013 - December 2013 at an average protection rate of $1.59/£1.00 and a trigger rate of $1.50/£1.00 as well as an additional £120 million in forward contracts for capital expenditure in the period Q2 2013 - Q1 2014 at an average rate of $1.52/£1.00.

CRITICAL ACCOUNTING ESTIMATES

Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These accounting policies are discussed below and are included to aid the reader in assessing the critical accounting policies and practices of the Corporation and the likelihood of materially different results being reported. Ithaca's management reviews these estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates.

The following assessment of significant accounting policies and associated estimates is not meant to be exhaustive. The Corporation might realize different results from the application of new accounting standards promulgated, from time to time, by various rule-making bodies.

Capitalized costs relating to the exploration and development of oil and gas reserves, along with estimated future capital expenditures required in order to develop proved and probable reserves are depreciated on a unit-of-production basis, by asset, using estimated proved and probable reserves as adjusted for production.

A review is carried out each reporting date for any indication that the carrying value of the Corporation's D&P assets may be impaired. For D&P assets where there are such indications, an impairment test is carried out on the Cash Generating Unit ("CGU"). Each CGU is identified in accordance with IAS 36. The Corporation's CGUs are those assets which generate largely independent cash flows and are normally, but not always, single developments or production areas. The impairment test involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use, where the value in use is determined from estimated future net cash flows. Any additional depreciation resulting from the impairment testing is charged to the Statement of Income.

Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each CGU to which the goodwill relates. Where the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognized in the Statement of Income. Impairment losses relating to goodwill cannot be reversed in future periods.

Recognition of decommissioning liabilities associated with oil and gas wells are determined using estimated costs discounted based on the estimated life of the asset. In periods following recognition, the liability and associated asset are adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The liability is accreted up to the actual expected cash outlay to perform the abandonment and reclamation. The carrying amounts of the associated assets are depleted using the unit of production method, in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred.

All financial instruments, other than those designated as effective hedging instruments, are initially recognized at fair value on the balance sheet. The Corporation's financial instruments consist of cash, restricted cash, accounts receivable, deposits, derivatives, accounts payable, accrued liabilities and the long term liability on the Beatrice acquisition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.

In order to recognize share based payment expense, the Corporation estimates the fair value of stock options granted using assumptions related to interest rates, expected life of the option, volatility of the underlying security and expected dividend yields. These assumptions may vary over time.

The determination of the Corporation's income and other tax liabilities / assets requires interpretation of complex laws and regulations. Tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded on the financial statements.

The accrual method of accounting will require management to incorporate certain estimates of revenues, production costs and other costs as at a specific reporting date. In addition, the Corporation must estimate capital expenditures on capital projects that are in progress or recently completed where actual costs have not been received as of the reporting date.

CONTROL ENVIRONMENT

Ithaca has established disclosure controls, procedures and corporate policies so that its consolidated financial results are presented accurately, fairly and on a timely basis. The Chief Executive Officer and Chief Financial Officer have designed, or have caused such internal controls over financial reporting to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of the Company's financial statements in accordance with IFRS with no material weaknesses identified.

Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements and even those options determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

As of December 31, 2012, there were no changes in our internal control over financial reporting that occurred during the year ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

CHANGES IN ACCOUNTING POLICIES

On January 1, 2011, the Corporation adopted IFRS using a transition date of January 1, 2010. The financial statements for the year ended December 31, 2012, including required comparative information, have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("IASB").

Following the introduction of IFRS the Corporation initially accounted for the acquisitions of the non-operated interests in the Cook field and of CMNSL as asset acquisitions. In Q4 2011 the Company subsequently elected to present all acquisitions since the IFRS transition date as business combinations in accordance with IFRS 3(R). This resulted in a restatement of the original accounting for the Cook acquisition (in Q3 2011) and the acquisition of gas assets from GDF (in Q4 2010) as shown in previous interim statements during 2011.

One impact of accounting for acquisitions as business combinations is the recognition of asset values, upon which the DD&A rate is calculated as pre-tax fair values and the recognition of a deferred tax liability on estimated future cash flows. With current tax rates at 62% this increases the DD&A charge for such assets. An offsetting reduction is recognized in the deferred tax charged through the consolidated statement of income.

IMPACT OF FUTURE ACCOUNTING CHANGES

In May 2011, the IASB issued the following standards: IFRS 10, Consolidated Financial Statements ("IFRS 10"), IFRS 11, Joint Arrangements ("IFRS 11"), IFRS 12, Disclosure of Interests in Other Entities ("IFRS 12"), IAS 27, Separate Financial Statements ("IAS 27"), IFRS 13, Fair Value Measurement ("IFRS 13") and amended IAS 28, Investments in Associates and Joint Ventures ("IAS 28"). Each of the new standards is effective for annual periods beginning on or after January 1, 2013 with early adoption permitted. The Corporation has decided not to early adopt any of the new requirements.

OTHER

Non-IFRS Measures

'Cashflow from operations' referred to in this MD&A is not prescribed by IFRS. This non-IFRS financial measure does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. The Corporation uses this measure to help evaluate its performance. As an indicator of the Corporation's performance, cashflow from operations should not be considered as an alternative to, or more meaningful than, net cash from operating activities as determined in accordance with IFRS. The Corporation considers Cashflow from operations to be a key measure as it demonstrates the Corporation's underlying ability to generate the cash necessary to fund operations and support activities related to its major assets. Cashflow from operations is determined by adding back changes in non-cash operating working capital to cash from operating activities.

BOE Presentation

The calculation of boe is based on a conversion rate of six thousand cubic feet of natural gas ("mcf") to one barrel of crude oil ("bbl"). The term boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 mcf: 1 bbl, utilizing a conversion ratio at 6 mcf: 1 bbl may be misleading as an indication of value.

Off Balance Sheet Arrangements

The Corporation has certain lease agreements and rig commitments which were entered into in the normal course of operations, all of which are disclosed under the heading "Commitments", above. Leases are treated as either operating leases or finance leases based on the extent to which risks and rewards incidental to ownership lie with the lessor or the lessee under IAS 17. No asset or liability value has been assigned to any leases on the balance sheet as at December 31, 2012.

Related Party Transactions

A director of the Corporation is a partner of Burstall Winger LLP who acts as counsel for the Corporation. The amount of fees paid to Burstall Winger LLP in 2012 was $0.1 million (2011: $0.2 million). These transactions are in the normal course of business and are conducted on normal commercial terms with consideration comparable to those charged by third parties.

As at December 31, 2012 the Corporation had a loan receivable from FPF-1 Ltd, an associate of the Corporation, for $21.6 million (2011: $Nil) as a result of the completion of the GSA transactions.

RISKS AND UNCERTAINTIES

The business of exploring for, developing and producing oil and natural gas reserves is inherently risky. There is substantial risk that the manpower and capital employed will not result in the finding of new reserves in economic quantities. There is a risk that the sale of reserves may be delayed due to processing constraints, lack of pipeline capacity or lack of markets. The Corporation is dependent upon the production rates and oil price to fund the current development program.

For additional detail regarding the Corporation's risks and uncertainties, refer to the Corporation's most recent AIF filed on SEDAR at www.sedar.com.

RISK

MITIGATIONS

Commodity Price Volatility

The Corporation's performance is significantly impacted by prevailing oil and natural gas prices, which are primarily driven by supply and demand as well as economic and political factors.

In order to mitigate the risk of fluctuations in oil and gas prices, the Corporation routinely executes commodity price derivatives, predominantly in relation to oil production, as a means of establishing a floor in realised prices.

Foreign Exchange Risk

The Corporation is exposed to financial risks including financial market volatility, fluctuation in interest rates and various foreign exchange rates.

Given the increasing proportion of development capital expenditure and operating costs incurred in currencies other than the United States dollar, the Corporation routinely executes hedges to mitigate foreign exchange rate risk on committed expenditure.

Debt Facility Risk

The Corporation is exposed to borrowing risks relating to drawdown of its senior secured borrowing base facility (the "Facility"). The ability to drawdown the Facility is based on the Corporation meeting certain covenants including coverage ratio tests, liquidity tests and development funding tests which are determined by a detailed economic model of the Corporation. There can be no assurance that the Corporation will satisfy such tests in the future in order to have access to the full amount of the Facility.

The Facility includes covenants which restrict, among other things, the Corporation's ability to incur additional debt or dispose of assets.

As is standard to a credit facility, the Corporation's and Ithaca Energy (UK) Limited's ("Ithaca UK") assets have been pledged as collateral and are subject to foreclosure in the event the Corporation or Ithaca UK defaults.

The Corporation believes that there are no circumstances at present that result in its failure to meet the financial tests and it can therefore draw down upon its Facility.

The Corporation routinely produces detailed cashflow forecasts to monitor its compliance with the financial tests and liquidity requirements of the Facility.

Financing Risk

To the extent cash flow from operations and Facility resources are ever deemed not adequate to fund Ithaca's cash requirements, external financing may be required. Lack of timely access to such additional financing, or access on unfavourable terms, could limit the future growth of the business of Ithaca. To the extent that external sources of capital, including public and private markets, become limited or unavailable, Ithaca's ability to make the necessary capital investments to maintain or expand its current business and to make necessary principal payments under the Facility may be impaired.

A failure to access adequate capital to continue its expenditure program may require that the Corporation meet any liquidity shortfalls through the selected divestment of its portfolio or delays to existing development programs.

The Corporation has established a fully funded business plan and routinely monitors its detailed cashflow forecasts and liquidity requirements to maintain its funding requirements. The Corporation believes that there are no circumstances at present that would lead to selected divestment, delays to existing programs or a default relating to the Facility.

Third Party Credit Risk

The Corporation is and may in the future be exposed to third party credit risk through its contractual arrangements with its current and future joint venture partners, marketers of its petroleum production and other parties. The Corporation extends unsecured credit to these parties, and therefore, the collection of any receivables may be affected by changes in the economic environment or other conditions.

The Corporation believes this risk is mitigated by the financial position of the parties. All of the Corporation's oil production from the Beatrice, Jacky and Athena fields is sold to BP Oil International Limited. Oil production from Cook and Broom is sold to Shell Trading International Ltd. Anglia and Topaz gas production is sold through contracts to RWE NPower PLC and Hess Energy Gas Power (UK) Ltd. Cook gas is sold to Shell UK Ltd. and Esso Exploration & Production UK Ltd. The Corporation has not experienced any material credit loss in the collection of accounts receivable to date.

The joint venture partners in those assets operated by the Corporation are largely well financed international companies. Where appropriate, a cash call process has been implemented with the GSA partners to cover high levels of anticipated capital expenditure thereby reducing any third party credit risk.

Property Risk

The Corporation's properties will be generally held in the form of licenses, concessions, permits and regulatory consents ("Authorizations"). The Corporation's activities are dependent upon the grant and maintenance of appropriate Authorizations, which may not be granted; may be made subject to limitations which, if not met, will result in the termination or withdrawal of the Authorization; or may be otherwise withdrawn. Also, in the majority of its licenses, the Corporation is often a joint interest-holder with another third party over which it has no control. An Authorization may be revoked by the relevant regulatory authority if the other interest-holder is no longer deemed to be financially credible.

There can be no assurance that any of the obligations required to maintain each Authorization will be met. Although the Corporation believes that the Authorizations will be renewed following expiry or granted (as the case may be), there can be no assurance that such Authorizations will be renewed or granted or as to the terms of such renewals or grants. The termination or expiration of the Corporation's Authorizations may have a material adverse effect on the Corporation's results of operations and business.

The areas covered by the Authorizations are or may be subject to agreements with the proprietors of the land. If such agreements are terminated, found void or otherwise challenged, the Corporation may suffer significant damage through the loss of opportunity to identify and extract oil or gas.

The Corporation has routine ongoing communications with the UK oil and gas regulatory body, DECC. Regular communication allows all parties to an Authorization to be fully informed as to the status of any Authorization and ensures the Corporation remains updated regarding fulfilment of any applicable requirements.

Operational Risk

The Corporation is subject to the risks associated with owning oil and natural gas properties, including environmental risks associated with air, land and water. All of the Corporation's operations are conducted offshore in the UKCS; as such Ithaca is exposed to operational risk associated with weather delays that can result in a material delay in project execution. Third parties operate some of the assets in which the Corporation has interests. As a result, the Corporation may have limited ability to exercise influence over the operations of these assets and their associated costs. The success and timing of these activities may be outside the Corporation's control.

There are numerous uncertainties in estimating the Corporation's reserve base due to the complexities in estimating the magnitude and timing of future production, revenue, expenses and capital.

The Corporation acts at all times as a reasonable and prudent operator. The Corporation takes out market insurance to mitigate many of these operational, construction and environmental risks.

The Corporation uses the services of Sproule International Limited to independently assess the Corporation's reserves on an annual basis.

Competition Risk

In all areas of the Corporation's business, there is competition with entities that may have greater technical and financial resources.

The Corporation places appropriate emphasis on ensuring it attracts and retains high quality resources to enable it to maintain its competitive position.

FORWARD-LOOKING INFORMATION

This MD&A and any documents incorporated by reference herein contain certain forward-looking statements and forward-looking information which are based on the Corporation's internal expectations, estimates, projections, assumptions and beliefs as at the date of such statements or information, including, among other things, assumptions with respect to production, future capital expenditures, future acquisitions and cash flow. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", "scheduled", "targeted", "approximately" and similar expressions are intended to identify forward-looking statements and forward-looking information. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. The Corporation believes that the expectations reflected in those forward-looking statements and information are reasonable but no assurance can be given that these expectations, or the assumptions underlying these expectations, will prove to be correct and such forward-looking statements and information included in this MD&A and any documents incorporated by reference herein should not be unduly relied upon. Such forward-looking statements and information speak only as of the date of this MD&A and any documents incorporated by reference herein and the Corporation does not undertake any obligation to publicly update or revise any forward-looking statements or information, except as required by applicable laws.

In particular, this MD&A and any documents incorporated by reference herein, contains specific forward-looking statements and information pertaining to the following:

• the quality of and future net revenues from the Corporation's reserves;

• oil, natural gas liquids ("NGLs") and natural gas production levels;

• commodity prices, foreign currency exchange rates and interest rates;

• capital expenditure programs and other expenditures;

• the sale, farming in, farming out or development of certain exploration properties using third party resources;

• supply and demand for oil, NGLs and natural gas;

• the Corporation's ability to raise capital;

• the continued availability of the Facility;

• the Corporation's acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived therefrom;

• the completion of the Valiant Acquisition;

• the realization of anticipated benefits from acquisitions and dispositions;

• the Corporation's ability to continually add to reserves;

• schedules and timing of certain projects and the Corporation's strategy for growth;

• the Corporation's future operating and financial results;

• the ability of the Corporation to optimize operations and reduce operational expenditures;

• treatment under governmental and other regulatory regimes and tax, environmental and other laws;

• production rates;

• targeted production levels; and

• timing and cost of the development of the Corporation's reserves.

With respect to forward-looking statements contained in this MD&A and any documents incorporated by reference herein, the Corporation has made assumptions regarding, among other things:

• Ithaca's ability to obtain additional drilling rigs and other equipment in a timely manner, as required;

• access to third party hosts and associated pipelines can be negotiated and accessed within the expected timeframe;

• FDP approval and operational construction and development is obtained within expected timeframes;

• the Corporation's development plan for the Stella and Harrier discoveries will be implemented as planned;

• the completion and effect of the Valiant Acquisition on Ithaca;

• reserves volumes assigned to Ithaca's properties;

• ability to recover reserves volumes assigned to Ithaca's properties;

• revenues do not decrease below anticipated levels and operating costs do not increase significantly above anticipated levels;

• future oil, NGLs and natural gas production levels from Ithaca's properties and the prices obtained from the sales of such production;

• the level of future capital expenditure required to exploit and develop reserves;

• Ithaca's ability to obtain financing on acceptable terms, in particular, the Corporation's ability to access the Facility;

• the continued ability of the Corporation to collect from third parties who Ithaca has provided credit to;

• Ithaca's reliance on partners and their ability to meet commitments under relevant agreements; and

• the state of the debt and equity markets in the current economic environment.

The Corporation's actual results could differ materially from those anticipated in these forward-looking statements and information as a result of assumptions proving inaccurate and of both known and unknown risks, including the risk factors set forth in this MD&A and under the heading "Risk Factors" in the AIF and the documents incorporated by reference herein, and those set forth below:

• risks associated with the exploration for and development of oil and natural gas reserves in the North Sea;

• risks associated with the integration of Valiant into Ithaca's existing operations;

• risks associated with offshore development and production including transport facilities;

• operational risks and liabilities that are not covered by insurance;

• volatility in market prices for oil, NGLs and natural gas;

• the ability of the Corporation to fund its substantial capital requirements and operations;

• risks associated with ensuring title to the Corporation's properties;

• changes in environmental, health and safety or other legislation applicable to the Corporation's operations, and the Corporation's ability to comply with current and future environmental, health and safety and other laws;

• the accuracy of oil and gas reserve estimates and estimated production levels as they are affected by the Corporation's exploration and development drilling and estimated decline rates;

• the Corporation's success at acquisition, exploration, exploitation and development of reserves;

• risks associated with realisation of anticipated benefits of acquisitions;

• risks related to changes to government policy with regard to offshore drilling;

• the Corporation's reliance on key operational and management personnel;

• the ability of the Corporation to obtain and maintain all of its required permits and licenses;

• competition for, among other things, capital, drilling equipment, acquisitions of reserves, undeveloped lands and skilled personnel;

• changes in general economic, market and business conditions in Canada, North America, the United Kingdom, Europe and worldwide;

• actions by governmental or regulatory authorities including changes in income tax laws or changes in tax laws, royalty rates and incentive programs relating to the oil and gas industry including any increase in UK taxes;

• adverse regulatory rulings, orders and decisions; and

• risks associated with the nature of the common shares.

Additional Reader Advisories

The information in this MD&A is provided as of March 25, 2013. The 2012 results have been compared to the results of 2011. This MD&A should be read in conjunction with the Corporation's consolidated financial statements as at December 31, 2012 and 2011 together with the accompanying notes and Annual Information Form ("AIF") for the 2012 fiscal year. Copies of these documents are available without charge from Ithaca or electronically on the internet on Ithaca's SEDAR profile at www.sedar.com.

With respect to Ithaca's reserves disclosure, the figures are derived from a report prepared by Sproule, an independent qualified reserves evaluator, evaluating the reserves of Ithaca as of December 31, 2012 and forming the basis for the Statement of Reserves Data and Other Oil and Gas information of Ithaca dated March 19, 2012 (the "Statement"). The reserves for the South West Heather field included in the Statement are those estimated by the Company and reviewed by Sproule. In respect of the MacCulloch field only (representing 1.4 MMboe proved plus probable reserves as at the same effective date, with Ithaca's previously announced acquisition of such field interest anticipated to be completed in 2013), Ithaca management prepared information reviewed by a qualified person under AIM guidelines.

With respect to Valiant reserves, the figures are derived from an Audit of Certain Reserves as at December 31, 2012 prepared by RPS Energy Consultants Limited, an independent qualified reserves evaluator, dated January 24, 2013. The reserves estimates of Ithaca are based on the Canadian Oil and Gas Evaluation Handbook ("COGEH") pursuant to Canadian National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities, with references to oil referring to medium quality oil.

The Ithaca reserves correspond to those in the Statement adjusted to reflect the increased Carna and Cook field equities acquired following the date of issue of the Statement and Ithaca management's estimate of MacCulloch field reserves. The reserves estimates of Valiant are based on the 2007 SPE/AAPG/WPC/ SPEE Petroleum Resource Management System which is not materially different from COGEH. The Valiant reserves have been adjusted to reflect the increased Fionn field interest being transferred to Valiant by Antrim Resources (N.I.) Limited.

If a discovery is made, there is no certainty that it will be developed, or if it is developed, there is no certainty as to the timing of such development or the benefits (if any) which may flow to the Company. Cashflow from operations includes the impact of executed hedges and does not include non-cash items such as DD&A, revaluation of financial instruments, impairments of fixed assets and movements

in goodwill, which may have a significant impact on the Company's results.

Statements relating to reserves are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

Consolidated Statement of Income

For the year ended 31 December 2012

Note

2012

US$'000

2011

US$'000

Revenue

4

170,477

129,059

Cost of Sales

5

(135,049)

(95,127)

Gross Profit

35,428

33,932

Exploration and evaluation expenses

10

(4,261)

(791)

Administrative expenses

6

(5,193)

(5,982)

Operating Profit

25,974

27,159

Foreign exchange

1,029

(755)

Gain/(loss) on financial instruments

23

6,739

(3,413)

Gain on asset disposal

11

205

-

Negative goodwill

-

15,210

Profit Before Interest and Tax

33,947

38,201

Finance costs

7

(4,930)

(1,521)

Interest income

218

434

Profit Before Tax

29,235

37,114

Taxation - Deferred tax

21

64,164

(1,246)

Profit After Tax

93,399

35,868

Earnings per share

Basic

20

0.36

0.14

Diluted

20

0.35

0.14

Consolidated Statement of Financial Position

as at 31 December 2012

2012

US$'000

2011

US$'000

ASSETS

Current assets

Cash and cash equivalents

31,374

95,545

Restricted cash

8

2

16,510

Accounts receivable

159,195

80,960

Deposits, prepaid expenses and other

14,754

8,793

Inventory

9

15,878

8,836

Derivative financial instruments

24

8,251

-

229,454

210,644

Non-current assets

Long-term receivable

26

21,551

-

Investment in associate

13

18,337

-

Exploration and evaluation assets

10

47,390

22,689

Property, plant & equipment

11

615,788

570,356

Goodwill

12

985

985

704,051

594,030

Total assets

933,505

804,674

LIABILITIES AND EQUITY

Current liabilities

Trade and other payables

205,635

102,136

205,635

102,136

Non-current liabilities

Decommissioning liabilities

15

52,834

39,382

Other long term liabilities

16

3,018

2,785

Deferred tax liabilities

21

62,370

126,534

Contingent consideration

17

4,000

24,580

Derivative financial instruments

24

-

1,846

122,222

195,127

Net Assets

605,648

507,411

Shareholders' Equity

Share capital

18

431,318

429,502

Share based payment reserve

19

20,340

17,318

Retained earnings

153,990

60,591

Total Equity

605,648

507,411

The financial statements were approved by the Board of Directors on 25 March 2013 and signed on its behalf by:

"John Summers"

Director

 "Jay Zammit"

Director

Consolidated Statement of Changes in Equity

For the year ended 31 December 2012

Share capital

Share based

payment

reserve

Warrants

issued

Retained

earnings

Total

US$'000

US$'000

US$'000

US$'000

US$'000

Balance, 1 Jan 2011

422,373

11,427

311

24,723

458,834

Profit for the period

-

-

-

35,868

35,868

Total comprehensive income

422,373

11,427

311

60,591

494,702

Share based payment

-

6,351

-

-

6,351

Options exercised

1,032

(460)

-

-

572

Warrants exercised (18(d))

6,097

-

(311)

-

5,786

Balance, 31 Dec 2011

429,502

17,318

-

60,591

507,411

Balance, 1 Jan 2012

429,502

17,318

-

60,591

507,411

Profit for the period

-

-

-

93,399

93,399

Total comprehensive income

429,502

17,318

-

153,990

600,810

Share based payment

-

3,817

-

-

3,817

Options exercised

1,816

(795)

-

-

1,021

Balance, 31 Dec 2012

431,318

20,340

-

153,990

605,648

Consolidated Statement of Cash Flow

For the year ended 31 December 2012

Note

2012

US$'000

2011

US$'000

CASH PROVIDED BY (USED IN):

Operating activities

Profit Before Tax

29,235

37,114

Adjustments for:

Depletion, depreciation and amortisation

11

56,172

31,447

Exploration and evaluation write off

10

4,261

2,791

Share based payment

6

866

1,399

Loan fee amortisation

7

1,087

311

Unrealised (gain)/loss on financial instruments

23

(4,142)

3,483

Revaluation of contingent consideration

17

1,295

(2,000)

Gain on disposal

11

(205)

-

Movement in goodwill

-

(15,210)

Accretion

7

1,777

858

Cashflow from operations

90,346

60,193

Changes in inventory, debtors and creditors relating to operating activities

(23,779)

43,276

Net cash from operating activities

66,567

103,469

Investing activities

Capital expenditure

(165,863)

(206,524)

Investment in associate

13

(18,337)

-

Expenditure on decommissioning

-

(358)

Loan to associate

26

(21,551)

-

Proceeds on disposal

11

44,878

-

Settlement of contingent consideration

(15,700)

-

Changes in debtors and creditors relating to investing activities

31,031

14,877

Net cash used in investing activities

(145,542)

(192,005)

Financing activities

Proceeds from issuance of shares

1,020

6,356

Decrease/(increase) in restricted cash

8

16,508

(10,202)

Derivatives

(2,485)

(6,508)

Net cash used in/from financing activities

15,043

(10,354)

Currency translation differences relating to cash & cash equivalents

(239)

(1,146)

(Decrease) in cash & cash equivalents

(64,171)

(100,036)

Cash and cash equivalents, beginning of period

95,545

195,581

Cash and cash equivalents, end of period

31,374

95,545

2012

US$'000

2011

US$'000

Oil sales

157,146

112,806

Gas sales

8,586

12,428

Condensate sales

501

995

Other income

4,244

2,830

Total

170,477

129,059

2012

US$'000

2011

US$'000

Operating costs

(85,478)

(48,295)

Movement in oil and gas inventory

6,601

(15,385)

Depletion, depreciation and amortisation

11

(56,172)

(31,447)

(135,049)

(95,127)

2012

US$'000

2011

US$'000

General & administrative

(4,327)

(4,584)

Share based payment

(866)

(1,398)

(5,193)

(5,982)

2012

US$'000

2011

US$'000

Accretion

15

(1,777)

(858)

Bank charges

(2,004)

(352)

Loan fee amortisation

(1,087)

(311)

Non-operated asset finance fees

(62)

-

(4,930)

(1,521)

2012

US$'000

2011

US$'000

Decommissioning security

-

16,167

Other security

2

343

2

16,510

2012

US$'000

2011

US$'000

Crude oil inventory

15,865

8,823

Materials inventory

13

13

15,878

8,836

US$'000

At 1 January 2011

17,832

Additions

7,752

Write offs/relinquishments

(2,791)

Disposals

(104)

At 31 December 2011

22,689

Additions

38,188

Write offs/relinquishments

(4,261)

Disposals

(9,226)

At 31 December 2012

47,390

Development & Production

Oil and Gas assets

US$'000

Other fixed

assets

US$'000

Total

US$'000

Cost

At 1 January 2011

281,411

1,587

282,998

Additions

342,138

705

342,843

At 31 December 2011

623,549

2,292

625,841

Additions

139,383

133

139,516

Disposals

(37,912)

-

(37,912)

At 31 December 2012

725,020

2,425

727,445

DD&A

At 1 January 2011

(22,934)

(1,104)

(24,038)

Charge for the period

(31,054)

(393)

(31,447)

At 31 December 2011

(53,988)

(1,497)

(55,485)

Charge for the period

(55,770)

(402)

(56,172)

At 31 December 2012

(109,758)

(1,899)

(111,657)

NBV at 1 January 2011

258,477

483

258,960

NBV at 1 January 2012

569,561

795

570,356

NBV at 31 December 2012

615,262

526

615,788

US$'000

Cost

At 1 January 2011, 31 December 2011 & 31 December 2012

985

2012

US$'000

2011

US$'000

Investments in FPF-1 and FPU services

18,337

-

2012

US$'000

2011

US$'000

Balance, beginning of period

39,382

23,652

Additions

9,613

15,250

Accretion

1,777

858

Revision to estimates

2,062

(20)

Utilisation

-

(358)

Balance, end of period

52,834

39,382