HIGHLIGHTS FIRST QUARTER 2013

HIGHLIGHTS FIRST QUARTER 2013 Strong cashflow from operations Cashflow from operations increased over 20% to $34.8 million (Q1 2012: $28.4 million) - cashflow per share $0.13 (Q1 2012: $0.11) Adjusted earnings of $14.6 million* excluding unrealised revaluation loss on financial instruments (Q1 2012: $12.1 million) o Unadjusted earnings of $3.5 million (Q1 2012: $12.9 million) Q1 2013 average realized oil price of $114 / bbl (Q1 2012: $116 / bbl), including a realized hedging gain of $8 / bbl Cash balance of $10.6 million net of drawn debt (Q4 2012: $31.4 million) UK tax allowances pool of $424 million at quarter end Approximately 2.6 million barrels of future 2013-14 oil production hedged at a weighted average price of around $106 / bbl (approximately 25% puts / 75% swaps) Q1 production in line with forecast Export production increased 51% to approximately 6,475 barrels of oil equivalent per day ( boepd ) (Q1 2012: 4,299 boepd), including production from the Cook field interest acquired from Noble Energy Capital Limited ( Noble ), effective January 1, 2012 Greater Stella Area hub major milestones being achieved FPF-1 floating production unit transferred to dry dock Contract signed with Applied Drilling Technology International ( ADTI ) in April 2013 to manage development drilling and completion operations on the Greater Stella Area ("GSA") under "turnkey" contract arrangements Ensco 100 drilling rig has now completed operations on the wells being drilled prior to commencement of the GSA development drilling programme rig scheduled to be on location at Stella field in Q2 2013 Fabrication of all the required subsea infrastructure that is to be installed by Technip in 2013 is progressing according to plan Step-change in growth of the Corporation Acquisition of Valiant Petroleum plc ( Valiant ) for a total enterprise value of approximately $459 million completed on April 19, 2013 Completion of the acquisition of an additional 12.885% interest in the Cook field ( the Cook Acquisition ) *Adjusted earnings removes the unrealised (non-cash) losses arising from revaluation of hedges at the quarter end. Revaluation at the end of April 2013 would have resulted in a gain as opposed to the loss of $11.1 million reported. 1

SUMMARY STATEMENT OF INCOME Q1 2013 Q1 2012 % Average Brent Oil Price $/bbl 113 119-5% Average Realised Oil Price (1) $/bbl 106 116-9% Revenue M$ 59.8 40.6 47% Cost of Sales excluding DD&A M$ (27.0) (12.6) 114% G&A etc M$ (1.9) 0.6 N/A Realised Derivatives Gain / (Loss) M$ 3.9 (0.2) N/A Cashflow From Operations M$ 34.8 28.4 23% DD&A M$ (19.5) (13.4) 46% Unrealised Derivatives Gain / (Loss) M$ (11.1) 0.8 N/A Other M$ (1.9) (2.0) -5% Profit Before Tax M$ 2.3 13.8-83% Deferred Tax Credit / (Charge) M$ 1.2 (0.9) N/A Profit After Tax M$ 3.5 12.9-73% Earnings Per Share (2) $/Sh. 0.01 0.05-80% Cashflow Per Share (2) $/Sh. 0.13 0.11 18% (1) Average realized price before hedging (2 Weighted average number of shares of 259.9 million pre Valiant Acquisition SUMMARY BALANCE SHEET M$ Q1 2013 Q4 2012 Cash & Equivalents 66 31 Other Current Assets 173 198 PP&E 749 663 Other Non-Current Assets 41 41 Total Assets 1,029 934 Current Liabilities (197) (206) Asset Retirement Obligations (57) (53) Deferred Tax Liabilities (103) (62) Other Non-Current Liabilities (62) (7) Total Liabilities (420) (328) Net Assets 609 606 Share Capital 431 431 Other Reserves 21 20 Surplus / (Deficit) 157 154 Shareholders Equity 609 606 2

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 25kboepd 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 ), Ithaca Minerals North Sea Limited ( Ithaca Minerals ) and Ithaca Energy Holdings (UK) Limited ( Ithaca Holdings UK ) 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. PRODUCTION & OPERATIONS UPDATE 51% increase in production compared to Q1 2012, with production in line with forecast performance 4.3 kboe/d 0.8 3.5 6.5 kboe/d 0.7 5.8 Q1 2012 Q1 2013 Oil Gas Q1 2013 PRODUCTION Ithaca s total net export production in Q1 2013 was 6,475 boepd, approximately 90% oil, representing an increase of approximately 51% on Q1 2012 production (Q1 2012: 4,299 boepd). The production performance was in the upper range of that anticipated by the Corporation as part of the 2013 annual production guidance range of 6,000 to 6,700 boepd. Production in the period was derived from the operated Athena, Beatrice, Jacky and Anglia fields and the non-operated Cook, Broom and Topaz fields. The total Q1 2013 production of 6,475 boepd includes the contribution from the additional 12.885% Cook field interest acquired from Noble. The material increase in production delivered in Q1 2013 compared to the same quarter in 2012 was primarily attributable to the contribution from the Athena field (first oil May 2012) and the acquisition of the additional Cook field interest from Noble. The two primary fields contributing approximately 70% of total net production during the quarter were Athena and Cook, with each contributing broadly equally. The Ithaca operated Athena field had another strong quarter, with the stable gross daily production potential of field remaining at between 10,000 and 11,000 bopd, 2,250 to 2,475 bopd net to Ithaca. Consistent daily delivery of the field potential over the period has been achievable as a result of the solid performance of the BW Athena floating, production, storage and offloading vessel ( FPSO ). The field continues to produce dry oil. 3

GREATER STELLA AREA DEVELOPMENT UPDATE GSA: Significant progress being made, with commencement of drilling campaign set for Q2-2013 FPF-1 Modification Works Following the transfer in late 2012 of the FPF-1 floating production facility to the Remontowa shipyard in Gdansk, Poland, the modifications work programme being performed by Petrofac in the yard has been focused on preparation for the dry dock. Inspection, repair and coating of the hull tanks is progressing well and the vessel has now been transferred to the yard s dry dock barge to enable completion of the marine system works. This milestone marks the start of the installation of additional buoyancy on the FPF-1 as part of the marine upgrade works, with steel cutting, rolling and welding operations in progress. Photo: FPF-1 transferred to dry dock barge in Remontowa yard, Gdansk ( Poland) Installation of the new topsides processing plant will commence upon completion of the dry dock works. The vessel preparatory works have largely been completed and delivery to the yard of the equipment and materials required for the construction and fabrication work programme has commenced. The gas export compressors, which represent the key processing plant package with the longest lead time (having being order at the start of 2012), have now been delivered to the yard. The FPF-1 is being modified and upgraded by Petrofac under the terms of a lump sum incentivised contract that was awarded by the GSA joint venture partners in October 2011. Drilling Programme The high-spec Ensco 100 heavy duty jack-up drilling rig that has been contracted for the GSA development drilling campaign has now completed operations on the wells being drilled for the North Sea operator that has being using the rig immediately prior to commencement of the GSA programme. The rig is being prepared for demobilisation from its current location and will shortly commence its transit to the Able shipyard in Hartlepool, UK, where Ensco will complete a scheduled routine inspection of the unit and certain minor upgrade works to improve the well construction capabilities of the rig specifically designed to improve the efficiency of GSA drilling operations. The unit is expected to arrive on location at the Stella field in Q2-2013. The initial development drilling campaign involves the completion of four wells on the Stella field prior to start-up of production. As previously announced, Advanced Drilling Technology International ( ADTI ), a subsidiary of Transocean, has been contracted to manage the drilling and completion operations under turnkey contract arrangements. The turnkey contract locks in the expenditure and performance requirements of the core drilling operations, with each well anticipated to take approximately 80-90 days to drill, complete and clean-up test. Subsea Infrastructure Works Significant progress is being made by Technip UK Limited ( Technip ) with preparation for the main subsea infrastructure installation activities that are scheduled to take place offshore in 2013. The subsea programme is being performed under the terms of an Engineering, Procurement, Installation and Construction ( EPIC ) contract, thereby ensuring a fully integrated execution plan covering all aspects of this key element of the GSA development. Manufacturing, coating and delivery to Technip s Evanton spool base in NE Scotland of all the required 10-inch export infrastructure linepipe has been completed and the welding of 12 metre pipes into 1000 metre pipe stalks has commenced. The pipe stalks are scheduled to be reeled on to Technip s Apache II pipelay vessel in Q3-2013 for subsequent installation offshore. Manufacture of the static flexible flowlines that will connect the drill centres to the FPF-1 is nearing completion at Technip s manufacturing facility in Le Trey, France. These are scheduled to be installed by the Skandi Arctic construction and dive support vessel, commencing in Q3-2013. The first pipeline trenches to be cut in advance of installation of the flexible flowlines will commence in Q2-2013, marking the start of the offshore installation campaign. Fabrication of the subsea structures that will connect the drill centres with the FPF-1 has been completed at Global Energy Group s facilities in NE Scotland. Installation and testing of the pipework spools, valves and control systems being fitted within the structures is nearing completion. The structures are scheduled to be installed by the Skandi Arctic in Q3-2013. 4

Q1 2013 CORPORATE ACTIVITIES Further broadening of the producing asset portfolio - acquisition of additional Cook field interest Acquisition of Cook Field Interest Completed, Lapse of MacCulloch Field Interest Acquisition In October 2012, the Corporation announced that it had entered into agreements with Noble Energy Capital Limited (a subsidiary of Noble Energy Inc.) to acquire a 12.885% interest in the Cook field and a 14% interest in the MacCulloch field. The acquisition of the Cook field interest was completed in February 2013, increasing the Corporation s overall interest in the field to 41.345%. The consideration paid at completion was $37.7 million, with approximately $14 million of this payment being offset by the transfer of oil inventory awaiting offload from the Anasuria floating production, storage and offloading vessel (the host facility for the Cook field) to the Corporation. The agreement for acquisition of the MacCulloch field interest from Noble has now lapsed and the Corporation has decided not to further pursue this acquisition given the field has remained shut-in since late December 2012. The MacCulloch field was only anticipated to contribute approximately 5% of the Corporation s total forecast 2013 production guidance of 6,000 to 6,700 boepd and represented 1.4MMbbl or less than 3% of the total 51.9MMbbl proved and probable ( 2P ) reserves at the end of 2012. ACQUISITION OF VALIANT PETROLEUM PLC Highly accretive acquisition - materially increasing production, reserves and cashflow On March 1, 2013, it was announced that the Boards of Ithaca and of Valiant reached agreement on the terms of a recommended acquisition (the Acquisition ) under which Ithaca would acquire all the shares of Valiant. The Acquisition was completed on April 19, 2013, with the cessation of trading of Valiant shares. The total Acquisition price was approximately $309 million. The Corporation also repaid approximately $150 million of Valiant debt / working capital, implying a total enterprise value of approximately $459 million. The Acquisition is financed by a low interest (London Inter Bank Offered Rate plus 1.0-1.6%) $350 million bridge loan and 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. The intention is to fold the borrowing secured against the Valiant assets into an enlarged borrowing base facility during 2013. A total of 56,952,321 new Ithaca common shares have been issued and allotted to holders of Valiant shares, immediately following which issue and allotment Ithaca had a total of 316,905,657 common shares outstanding. Admission of the new shares to trading on the Alternative Investment Market ( AIM ) and the Toronto Stock Exchange occurred by April 22, 2013. The Acquisition has resulted 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 14-16kboepd (90% oil), forecast to rise to approximately 27kboepd in 2015; and Anticipated four fold increase in Ithaca's anticipated 2013 cash flow from operations to $400 million, rising to over $700 million in 2015. 5

COMMODITY HEDGING At the start of Q1 2013 approximately 3 million barrels of 2013-14 oil production had been hedged at a weighted average price of $109 / bbl (approximately 25% puts / 75% swaps). In the quarter, the Corporation received $4.2 million through the settlement of commodity hedges relating to approximately 0.4 million barrels of oil. In April 2013, the Corporation exercised an option to swap 1 million barrels of production at $107/bbl. On the day of exercise, the Brent forward curve, for the period to which the hedge related, was at $101 / bbl resulting in the swaption being converted to a cash settlement of $6 million and a forward swap of 1 million barrels of production at $101 / bbl. Following the above transactions, 2.6 million barrels of future 2013-14 oil production are hedged at a weighted average price of ~ $106 / bbl (approximately 25% puts / 75% swaps). The unrealised losses of $11.1 million from the revaluation of financial instruments included a loss of $9.1 million driven by the revaluation of oil swaps and put options. The hedging instruments are measured at March 31, 2013 and a valuation attributed based on the Brent oil forward curve on that date (spot Brent was trading at $108.46/bbl on March 31, 2013). The losses relate to movement in the Brent oil forward curve, a reduction in the implied volatility and the elapsing of time. Whilst significant, these marked-to-market movements represent non-cash revaluations which are highly sensitive to the oil price on the day of valuation and do not affect underlying cashflow from operations. For example, had the revaluation taken place at the end of April 2013, the revaluation would have resulted in a gain rather than a loss. 6

Q1 2013 RESULTS OF OPERATIONS REVENUE 41 60 Revenue increased by $19.2 million in Q1 2013 to $59.8 million (Q1 2012: $40.6 million). This was mainly driven by an increase in oil sales volumes, partially offset by a reduction in oil price. Oil sales volumes increased primarily due to the inclusion of sales from the Athena field and the Cook Acquisition in Q1 2013 (Athena commenced production in May 2012) offset by natural declines in the Beatrice and Jacky fields. Of the reported 6,475 boepd production, 6,148 boepd flows through the statement of income with the additional 327 boepd reflecting production from the Cook Acquisition prior to completion. The value of the pre-completion production is captured as part of the acquisition accounting on the balance sheet. Q1 2012 Q1 2013 Oil Gas Other Record quarterly revenue of $59.8 million Q1 2013 gas sales are in line with Q1 2012 despite a reduction in Anglia and Topaz gas volumes, which was offset by the addition of Cook gas sales as well as an increase in realized gas prices. Average realized oil prices decreased quarter on quarter from $116/bbl in Q1 2012 to $106/bbl in Q1 2013. The average Brent price for the quarter was $113/bbl compared to $119/bbl for Q1 2012. 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 $8/bbl in Q1 2013. Average Realized Price Q1 2013 Q1 2012 Oil Pre-Hedging $/bbl 106 116 Oil Post-Hedging $/bbl 114 116 Gas $/boe 47 41 COST OF SALES 29 M $ 4.3 9.1 15.7 43 M $ 4.9 14.5 23.2 Q1 2013 $ 000 Q1 2012 $ 000 Q1 2013 $/boe Q1 2012 $/boe Operating Expenditure 23,227 15,721 42 40 DD&A 19,498 13,385 35 34 Movement in Oil & Gas Inventory 3,576 (3,100) - - Oil purchases 157 - - - Total 46,458 26,006 84 66. Opex DD&A DD&A (BC uplift) Q1 2012 Q1 2013 Figures stated in $ million (graph excludes movement in oil & gas inventory) Cost of sales increased in Q1 2013 to $46.5 million (Q1 2012: $26.0 million) due to increases in operating costs, depletion, depreciation and amortization ( DD&A ) and movement in oil and gas inventory. Operating costs increased in the quarter to $23.2 million (Q1 2012: $15.7 million) primarily due to the inclusion of Athena operating costs (nil Q1 2012) and the additional acquired interest in Cook. Operating costs/boe increased to $42/boe in the period (Q1 2012: $40) mainly as a result of the phasing of Cook costs in 2012 with lower costs in the first quarter 2012 compared to the comparative period 2013. Although operating costs per boe are up compared to Q1 2012, a combined rate of $42/boe for Q1 is in line with the Corporation s forecast to reduce operating costs for its current portfolio (excluding Valiant assets) for the full year to under $40/boe. The absence of production from other fields sharing the FPSO through which Cook oil is exported gives rise to the higher allocation of costs in the quarter. The other main field producing across the FPSO (in which Ithaca has no equity interest) recommenced production at the start of May, ahead of forecast, supporting the expectation of a lower operating cost per barrel over the year. 7

DD&A expense for the quarter increased to $19.5 million (Q1 2012: $13.4 million). This was primarily due to higher production volumes in Q1 2013 with the addition of the Athena field as well as the recently acquired additional interest in Cook. The blended rate for the quarter was relatively unchanged at $35/boe (Q1 2012: $34/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. 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 Statement of Income. An oil and gas inventory movement of $3.6 million was charged to cost of sales in Q1 2013 (Q1 2012 credit of $3.1 million). 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 Q1 2013 more barrels of oil were sold (528k bbls) than produced (495k bbls), as a result of timings of Cook liftings and Athena shuttle tankers. Volumes account for $3.8 million of the movement, partially offset by a credit of $0.2 million due to the change in valuation of the opening inventory barrels. Movement in oil & gas inventory Oil kbbls Gas kboes Total kboes Operating inventory 149 13 162 Production 496 57 553 Liftings/sales (527) (59) (586) Acquired volumes 124-124 Closing volumes 241 11 253 8

ADMINISTRATION & EXPLORATION & EVALUATION EXPENSES $ 000 Q1 2013 Q1 2012 General & Administration 2,476 1,071 Share Based Payments 295 135 Total Administration Expenses 2,771 1,206 Exploration & Evaluation 312 75 Total 3,083 1,281 Total administrative expenses increased in the quarter to $2.8 million (Q1 2012: $1.2 million) primarily due to an increase in general and administrative expenses as a result of higher levels of corporate activity ongoing in the quarter, particularly in relation to the Acquisition of Valiant. Share based payment expenses increased as a result of options being granted towards the end of 2012 (none end 2011), therefore higher amortisation expense has been reflected through Q1 2013. Exploration and evaluation expenses of $0.3 million were recorded in the quarter (Q1 2012: $0.1 million) primarily due to the expensing of previously capitalized costs relating to areas where exploration and evaluation activities have ceased. FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS USD:GBP Exchange rates 1.64 1.62 1.6 1.58 1.56 1.54 1.52 1.5 1.48 1.46 Dec-12 Jan-13 Feb-13 Mar-13 A foreign exchange gain of $0.6 million was recorded in Q1 2013 (Q1 2012: $1.6 million). 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, 2013: 1.62. USD:GBP at March 31, 2013: 1.52 with fluctuation between 1.48 and 1.64 during the quarter). This volatility was partially offset by foreign exchange hedges as described in the Risks and Uncertainties section below. The Corporation recorded a $7.2 million loss on financial instruments for the quarter ended March 31, 2013 (Q1 2012: $0.7 million loss). The loss was predominantly due to a $9.1 million reduction in value of oil swaps and put options, due to a relatively strong Brent oil price at quarter end together with a reduction in implied volatility in the period and the elapsing of time. In addition, the Corporation recorded a $2.1 million loss on the revaluation of foreign exchange instruments. The Corporation s exposure to fluctuations in the USD:GBP exchange rate has nonetheless been limited due to the forward contracts entered into to hedge 120 million of capital expenditure on the GSA development at a rate of $1.52: 1.00. The revaluation losses were partially offset by a $4.2 million realized gain on commodity hedges. TAXATION No UK tax anticipated to be payable in the mid-term A deferred tax credit of $1.2 million was recognized in the quarter ended March 31, 2013 (Q12012: $0.9 million charge). This credit is a product of adjustments to the tax charge primarily relating to the UK Ring Fence Expenditure Supplement and share based payments. 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 $3.5 million (Q12012: $12.9 million). 9

No taxes are expected to be paid in the mid-term relating to upstream oil and gas activities as a result of the $424 million tax losses available to the Corporation. CAPITAL INVESTMENTS $ 000 Q1 2013 Q1 2012 Development & Production ( D&P ) 103,070 26,539 Exploration & Evaluation ( E&E ) 2,108 1,254 Other Fixed Assets 31 26 Total 105,209 27,819 $70.9 million of the total $103.1 million capital additions to D&P assets in Q1 2013 was attributable to the acquisition of the additional interest in the Cook field, of which $37.7 million represents cash paid with the remainder being due to business combination accounting. The remaining D&P additions were primarily focused on execution of the GSA development, with the main areas of expenditure being on the manufacture and fabrication of subsea infrastructure and the FPF-1 modification works (as described above). Capital expenditure on E&E assets in Q1 2013 was $2.1 million with spending primarily focused on Hurricane and development projects. LIQUIDITY AND CAPITAL RESOURCES Significant investment in development projects $ 000 Q1 2013 Q4 2012 Increase / (Decrease) Cash & Cash Equivalents 65,636 31,376 34,260 Trade & Other Receivables 139,915 173,949 (34,034) Inventory 26,131 15,878 10,253 Trade & Other Payables (194,278) (205,635) 11,357 Net Working Capital 37,404 15,568 21,836 As at March 31, 2013, Ithaca had working capital of $37.4 million including a cash balance of $65.6 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 increased as a result of $55 million of bank debt drawings towards the end of the quarter offsetting the continued cash investment in the Stella development. The funds were required for substantial payments due for imminent release post March 31, 2013 on the Stella project together with funds required to be held over as part of the Valiant Acquisition. Other working capital movements are driven by the timing of receipts and payments of balances. 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 March 31, 2013, 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 March 31, 2013, Ithaca had unused credit facilities totalling $375 million (Q4 2012: $430 million). $55 million was drawn down under this facility in Q1 2013. 10

Cashflow evolution During the quarter ended March 31, 2013, there was a net cash inflow of approximately $34.8 million (Q1 2012: outflow of $5.6 million). Cashflow from operations Cash generated from operating activities was $34.8 million primarily due to cash generated from Athena, Beatrice, Jacky, Anglia, Cook and Broom operations, augmented in Q1 2013 primarily due to the inclusion of Athena. Cashflow from financing activities Cash generated from financing activities was $46.0 million primarily due to the draw down of the existing debt facility in Q1 2013 ($55 million), partially offset by oil hedging premiums paid. Cashflow from investing activities Cash used in investing activities was $59.4 million primarily due to capital expenditure on the Cook Acquisition and the GSA development, including modification of the FPF-1, subsea design and fabrication works. 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 $ 000 1 Year 2-5 Years 5+ Years Office Leases 423 1,421 - Other Operating Leases 12,319 14,300 - Exploration Licence Fees 583 - - Engineering 53,550 - - Rig Commitments 37,305 - - Total 104,180 15,721 - 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 11

stated above, these commitments are expected to be funded through the Corporation s existing cash balance, forecast cashflow from operations and its 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 March 31, 2013, Ithaca had 259,953,336 common shares outstanding along with 20,344,631 options outstanding to employees and directors to acquire common shares. In Q1 2013, the Corporation s Board of Directors granted 90,000 options at a weighted average exercise price of C$1.79. 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 May 10, 2013, following completion of the Valiant Acquisition, Ithaca had 317,088,991 common shares outstanding along with 20,011,297 options outstanding to employees and directors to acquire common shares. March 31, 2013 Common Shares Outstanding 259,953,336 Share Price (1) $1.70 / Share Total Market Capitalisation $441,920,671 (1) Represents the TSX close price (CAD$1.73 on last trading day of March, 2013. US$:CAD$ 0.9825 on March 31, 2013 SUMMARY OF QUARTERLY RESULTS $ 000 31 Mar 2013 31 Dec 2012 30 Sep 2012 30 Jun 2012 31 Mar 2012 31 Dec 2011 30 Sep 2011 Restated 30 Jun 2011 Revenue 59,769 52,566 41,579 35,779 40,553 54,870 26,415 16,724 Profit After Tax 3,472 45,347 4,894 30,238 12,916 13,318 16,016 2,743 EPS - Basic 0.01 0.17 0.02 0.12 0.05 0.05 0.06 0.01 EPS - Diluted 0.01 0.17 0.02 0.11 0.05 0.05 0.06 0.01 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. 12

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 hedges 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 March 31, 2013. The table below presents the total gain / (loss) on financial instruments that has been disclosed through the statement of comprehensive income. $ 000 Q1 2013 Q1 2012 Revaluation Forex Forward Contracts (2,055) 969 Revaluation of Gas Contract - (114) Revaluation of Other Long Term Liability 57 (90) Revaluation of Commodity Hedges (9,067) - Total Revaluation Gain / (Loss) (11,065) 765 Realised Loss on Forex Contracts (293) - Realised Gain/(Loss) on Commodity Hedges 4,186 (199) Total Realised Gain/(Loss) 3,893 (199) Total Realised / Revaluation Gain / (Loss) (7,172) 566 Contingent Consideration - (1,294) Total (Loss) on Financial Instruments (7,172) (728) The following table summarises the commodity hedges in place at the beginning of the quarter. Derivative Term Volume bbl Average Price $/bbl Oil Swaps* January 2013 September 2014 2,297,753 108.0 Put Options January 2013 March 2014 779,299 110.4 Derivative Term Volume Therms Average Price p/therm Gas Swaps January 2013 December 2014 3,066,000 66.45 *Includes swaption of 1 million bbls which was exercised in April 2013 13

The table below summarises the foreign exchange financial instruments in place during Q1 2013. Derivative Forward Plus Forward contract Term Jan 13 Dec 13 Apr 13 Jan 14 Value 4million / month 120 million Protection Rate $1.59/ 1.00 $1.52/ 1.00 Trigger Rate $1.50/ 1.00 N/A 14

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. 15

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 Corporation 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 March 31, 2013, there were no changes in Ithaca s internal control over financial reporting that occurred during the quarter ended March 31, 2013 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 quarter ended March 31, 2013, including required comparative information, have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("IASB"). The Corporation elected to present all acquisitions since the IFRS transition date as business combinations in accordance with IFRS 3(R). 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. 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 1 January 2013. There has been no material impact from the adoption of the new and amended standards on the Corporation's financial statements. 16

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 March 31, 2013. 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 Q1 2013 was $0.1 million (Q1 2012: $Nil). 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 March 31, 2013 the Corporation had a loan receivable from FPF-1 Ltd, an associate of the Corporation, for $21.6 million (Q1 2012: $Nil) as a result of the completion of the GSA transactions in 2012. 17

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 Annual Information Form dated March 25, 2013, (the AIF ) filed on SEDAR at www.sedar.com. Commodity Price Volatility RISK 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. MITIGATIONS 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 cashflow 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 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. 18

Third Party Credit Risk 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 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 The Corporation has routine ongoing communications with the UK oil and gas regulatory body, the Department of Energy and Climate Change ( 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. 19