Third Quarter 2012 Financial Results

Not for Distribution to U.S. Newswire Services or for Dissemination in the United States

Ithaca Energy Inc.

Third Quarter 2012 Financial Results

Ithaca Energy Inc. (TSX: IAE, LSE AIM: IAE) announces its quarterly financial results for the three months ended September 30, 2012.

HIGHLIGHTS

Financial

·; Q3 profit before tax and unrealised gains/losses on financial instruments of $14.9 million (Q3 2011: $15.6 million) representing an increase of $10.5 million on Q2 2012 (Q2 2012: $4.4 million)

·; Q3 net earnings of $4.9 million including $12.9 million unrealised loss from financial instruments (Q3 2011: $16.0 million) resulting in earnings per share of $0.02 (Q3 2011: $0.06)

·; Q3 cashflow from operations of $30.1 million (Q3 2011: $18.1 million). Q3 cashflow per share of $0.12 (Q3 2011: $0.07)

·; Q3 average realised oil price of $110.26 / bbl (Q3 2011: $111.24 / bbl) plus an additional realized hedging gain of $2.56 / bbl in the quarter

·; Cash of $77.4 million, inclusive of $20.6 million restricted cash, with senior debt facility remaining undrawn

·; UK tax allowances pool of $387 million representing an increase of $39 million on Q2 2012 (Q2 2012: $348 million)

Operational & Corporate

·; Q3 export production of 5,061 barrels of oil equivalent per day ("boepd") (Q3 2011: 3,602 boepd). This represents an increase of approximately 28% on the second quarter of 2012, reflecting the first full quarter's production from the Athena field and a strong performance from the Beatrice and Jacky fields compensating for the anticipated reduction in Cook and Broom production during the quarter due to planned maintenance shutdowns

·; Production from the Athena field stabilised at a gross rate of 10,000 to 11,000 barrels of oil per day ("bopd"), 2,250 to 2,475 bopd net to Ithaca, with the field continuing to produce "dry" oil

·; Hurricane appraisal well successfully drilled, identifying hydrocarbons in two reservoir intervals,with pressure and fluid samples recovered from both intervals and a drill stem test performed on the Andrew sand reservoir

·; An Engineering, Procurement, Installation and Construction ("EPIC") contract was awarded to Technip UK Limited covering the major subsea works that are to be conducted on the Greater Stella Area, with installation of the subsea infrastructure scheduled for 2013

·; Entered into further swaps of 503,800 barrels of oil at a weighted average price of $108.67 and put options, at market price, for 300,300 barrels of oil at a weighted average oil price floor of $111.34 / bbl for the period October 2012 to December 2013.

POST QUARTER END EVENTS

·; Entered into agreements with Noble Energy Capital Limited to acquire corporate entities owning non-operated interests in two United Kingdom ("UK") North Sea producing fields: a 12.885% interest in the Cook field (increasing the Company's field interest in Cook to 41.345%) and a 14% interest in the MacCulloch field. The total acquisition consideration is $38.5 million and is to be funded from the Company's existing cash resources. The two fields are anticipated to increase the Company's net proved and probable reserves by approximately 3.4 mmboe based on the effective date of the transaction of 1 January 2012.

·; Closure of oversubscribed syndication of $430 million debt facility with BNP Paribas and six other leading international banks working in the oil and gas sector

·; Offered two Blocks by the Department of Energy and Climate Change in the 27th UK Licence Round - Block 29/5e in the vicinity of the Company's existing Greater Stella Area ("GSA") interests and Block 15/17b in the Outer Moray Firth

·; The Company has issued today a full update on the progress made on the Greater Stella Area development.

Notes:

Unrealised gains/losses on financial instruments are non-cash mark to market movements on derivative instruments that account for the fair value of an asset or liability based on the current market price using quoted market prices when available, or industry accepted third-party models and valuation methodologies that utilise observable market data.

Further details on the above are provided in the Interim Consolidated Financial Statements and Management's Discussion and Analysis for the three and nine months ended September 30, 2012, which have been filed with securities regulatory authorities in Canada. These documents are available on the System for Electronic Document Analysis and Retrieval at www.sedar.com and on the Company's website: www.ithacaenergy.com.

Notes to oil and gas disclosure:

In accordance with AIM Guidelines, John Horsburgh, BSc (Hons) Geophysics (Edinburgh), MSc Petroleum Geology (Aberdeen) and Subsurface Manager at Ithaca is the qualified person that has reviewed the technical information contained in this press release. Mr Horsburgh has over 15 years operating experience in the upstream oil industry.

The term "boe" may be misleading, particularly if used in isolation. A boe conversion 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.

Enquiries:

Ithaca Energy Inc.

Iain McKendrick, CEO [email protected] +44 (0) 1224 650 261

Graham Forbes, CFO [email protected] +44 (0) 1224 652 151

NOMAD and Joint Broker: Cenkos Securities plc

Jon Fitzpatrick [email protected] +44 (0) 207 397 8900

Ken Fleming [email protected] +44 (0) 131 220 6939

Joint Broker: RBC Capital Markets

Tim Chapman [email protected] +44 (0) 207 653 4641

Matthew Coakes [email protected] +44 (0) 207 653 4871

Public Relations: 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

About Ithaca Energy:

Ithaca Energy Inc. (TSX: IAE, LSE AIM: IAE) and its wholly owned subsidiary Ithaca Energy (UK) Limited ("Ithaca" or "the Company"), is an oil and gas operator focused on production, appraisal and development activities on the United Kingdom Continental Shelf. The goal of Ithaca, in the near term, is to maximize production and achieve early production from the development of existing discoveries on properties held by Ithaca, to originate and participate in exploration and appraisal on properties held by Ithaca when capital permits, and to consider other opportunities for growth as they are identified from time to time by Ithaca.

Not for Distribution to U.S. Newswire Services or for Dissemination in the United States

Reader Advisory

Forward-looking statements

This news release contains certain forward looking statements. The reader is cautioned that all such forward looking statements involve substantial risks and uncertainties and the assumptions used in their preparation may not prove to be correct. Ithaca's actual results could differ materially from those expressed in, or implied by, these forward looking statements and accordingly, the forward looking statements are qualified by reference to these cautionary statements. The forward looking statements contained herein are made as at the date of this news release. Ithaca undertakes no obligation to update or publicly revise forward looking statements or information unless so required by applicable securities laws.

TSX notifications

The TSX accepts no responsibility for the adequacy or accuracy of this release.

Cenkos Securities plc, which is authorised and regulated in the United Kingdom by the Financial Services Authority under FSA number 416932, is acting exclusively as Nominated Adviser and Joint Broker to the Company and is not acting for or advising any other person and accordingly will not be responsible to any person other than the Company for providing advice in relation to the contents of this announcement. Neither Cenkos Securities plc nor any of its affiliates owes or accepts any duty, liability or responsibility whatsoever (whether direct or indirect, whether in contract, in tort, under statute or otherwise) to any person who is not a customer of Cenkos Securities plc in connection with this announcement, any statement contained herein or otherwise.

This announcement is not intended to, and does not, constitute or form part of any offer, invitation or the solicitation of an offer to purchase, otherwise acquire, subscribe for, sell or otherwise dispose of, any securities whether pursuant to this announcement or otherwise.

ITHACA ENERGY INC.

MANAGEMENT'S DISCUSSION AND ANALYSISFOR THE QUARTER ENDED SEPTEMBER 30, 2012

The following is management's discussion and analysis ("MD&A") of the operating and financial results of Ithaca Energy Inc. (the "Corporation" or "Ithaca" or the "Company") for the three and nine months ended September 30, 2012. The information is provided as of November 9, 2012. The third quarter 2012 results have been compared to the results of the comparative period in 2011. This MD&A should be read in conjunction with the Corporation's unaudited consolidated financial statements as at September 30, 2012 and with the Corporation's audited consolidated financial statements as at December 31, 2011 together with the accompanying notes, MD&A and Annual Information Form ("AIF") for the 2011 fiscal year. These documents and additional information about Ithaca are available on SEDAR at www.sedar.com.

Certain statements contained in this MD&A, including estimates of reserves, estimates of future cash flows and estimates of future production as well as other statements about future events or anticipated results, are forward-looking statements. The forward-looking statements contained herein are based on assumptions and are subject to known and unknown risks, uncertainties and other factors. Should the underlying assumptions prove incorrect or should one or more of these risks, uncertainties or factors materialize, actual results may vary significantly from those expected. See "Forward-Looking Information", below.

All financial data contained herein is presented in accordance with International Financial Reporting Standards ("IFRS") and is expressed in United States dollars ("$"), unless otherwise stated.

BUSINESS OF THE CORPORATION

Ithaca is an oil and gas company focused on production, appraisal, and development activities in the United Kingdom's Continental Shelf ("UKCS").

Ithaca's strategy is to:

·; Fast track, appraise and develop oil and gas fields

·; Acquire producing fields or undeveloped discoveries that:

o are not material for larger companies

o need technical or financial investment

o no longer fit with an existing company's strategy and business model

·; Use tried and tested development and production technologies

·; Employ in-house technical excellence to generate development and acquisition opportunities

·; Participate in licensing rounds to gain acreage positions around its core assets

·; Lever its commercial and operator capability to establish solid oil and gas field positions

·; Prioritize capital investment to accretive projects with early production and significant cash flow

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

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.

'Profit before tax and unrealised gains/losses on financial instruments' 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, Profit before tax and unrealised gains/losses on financial instruments should not be considered as an alternative to, or more meaningful than, Profit before tax as determined in accordance with IFRS. The Corporation considers Profit before tax and unrealised gains/losses on financial instruments to be a key measure as it demonstrates the Corporation's underlying profitability, stripping out the effects of non cash financial instrument gains / losses. Profit before tax and unrealised gains/losses on financial instruments is determined by deducting / adding back non-cash gains / losses on financial instruments.

BOE PRESENTATION

The calculation of barrels of oil equivalent ("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.

HIGHLIGHTS THIRD QUARTER 2012

Financial

·; Q3 profit before tax and unrealised gains/losses on financial instruments of $14.9 million (Q3 2011: $15.6 million)

·; Q3 net earnings of $4.9 million including $12.9 million unrealised loss from financial instruments (Q3 2011: $16.0 million) resulting in earnings per share of $0.02 (Q3 2011: $0.06)

·; Q3 cashflow from operations of $30.1 million (Q3 2011: $18.1 million). Q3 cashflow per share of $0.12 (Q3 2011: $0.07)

·; Q3 average realized oil price of $110.26 / bbl (Q3 2011: $111.24 / bbl) plus an additional realized hedging gain of $2.56 / bbl in the quarter

·; Cash of $77.4 million, inclusive of $20.6 million restricted cash, with fully syndicated senior debt facility of $430 million remaining undrawn

·; UK tax allowances pool of $387 million

Operational & Corporate

·; Q3 export production of 5,061 barrels of oil equivalent per day ("boepd") (Q3 2011: 3,602 boepd) - a 40% increase despite the planned maintenance shutdown of the Cook field during the quarter

·; Production from the Athena field stabilised at a gross rate of 10,000 to 11,000 barrels of oil per day ("bopd"), 2,250 to 2,475 bopd net to Ithaca, with the field continuing to produce "dry" oil

·; Hurricane appraisal well successfully drilled, identifying hydrocarbons in two reservoir intervals, with pressure and fluid samples recovered from both intervals and a highly successful drill stem test performed on the Andrew sand reservoir

·; An Engineering, Procurement, Installation and Construction ("EPIC") contract was awarded to Technip UK Limited covering the major subsea works that are to be conducted on the Greater Stella Area, with installation of the subsea infrastructure scheduled for 2013

·; Entered into further swaps of 503,800 barrels of oil at a weighted average price of $108.67 and put options, at market price, for 300,300 barrels of oil at a weighted average oil price floor of $111.34 / bbl for the period October 2012 to December 2013.

Post quarter end

·; Entered into agreements with Noble Energy Capital Limited to acquire corporate entities owning non-operated interests in two United Kingdom ("UK") North Sea producing fields: a 12.885% interest in the Cook field (increasing the Company's field interest in Cook to 41.345%) and a 14% interest in the MacCulloch field. The total acquisition consideration is $38.5 million and is to be funded from the Company's existing cash resources. The two fields are anticipated to increase the Company's net proved and probable reserves by approximately 3.4 mmboe based on the effective date of the transaction of 1 January 2012

·; Closure of an oversubscribed syndication of $430 million debt facility (the "Facility") with BNP Paribas ("BNPP") and six other leading international banks working in the oil and gas sector

·; Offered two Blocks by the Department of Energy and Climate Change ("DECC") in the 27th UK Licence Round - Block 29/5e in the vicinity of the Company's existing Greater Stella Area ("GSA") interests and Block 15/17b in the Outer Moray Firth

·; The Company has issued today a full update on the progress made on the Greater Stella Area development.

KEY PROJECTS AND OPERATIONS UPDATE

Athena

Start up of oil production from the Athena field was achieved in late May 2012. The early part of Q3 2012 was focused on completing and optimising the post start-up activities required to deliver stable and efficient operations from the wells and the BW Athena Floating Production, Storage and Offloading vessel ("FPSO"). Well intervention activities were performed on the "P1" well during the quarter to attempt to eliminate a blockage in the production tubing of the P1 well. These operations, involving the pumping of fluids into the P1 well, were partially successful and the well was put onstream in September at a gross production rate of approximately 700 to 800 barrels of oil gross per day ("bopd"). A decision was made by the Athena co-venturers not to perform a rig based workover on P1 to fully remove the blockage as the reserves associated with the well are anticipated to be recovered by the existing wells on the field.

Production from the field has stabilised at a gross daily rate of between 10,000 and 11,000 bopd, 2,250 to 2,475 bopd net to Ithaca. Reservoir performance, including the continued production of dry oil, provides a positive signal for the longer term potential of the field. The timing of water breakthrough at the Athena wells, 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 and will be built into a range of production forecasts by the Company.

Greater Stella Area

 Greater Stella Area

Significant progress has been made with delivery of the Company's GSA strategy and execution of the Stella and Harrier development project since the Field Development Plan ("FDP") for the two fields was approved by the DECC in April 2012.

An update on the progress made with the GSA development activities and schedule has today been issued by the Company. The key points contained in the release are:

o The modifications contract for the "FPF-1" floating production unit has been awarded to the Remontowa shipyard in Gdansk, Poland. The FPF-1 is now located In Gdansk.

o The Ensco 100 drilling rig is now forecast to commence the development drilling campaign in Q1-2013, due to delays in the completion of drilling programmes for other operators.

o Four initial Stella wells are to be drilled over a period of approximately twelve months prior to the arrival of the FPF-1 for hook-up and commissioning, currently anticipated in H1-2014.

o Detailed design has been completed for the subsea infrastructure that is to be installed in 2013 by Technip, a world leader in the execution of subsea projects. Fabrication of the required linepipe is underway.

o A suite of gas transportation and processing agreements has been executed for export of gas processed on the FPF-1 via the Central Area Transmission System ("CATS") and Teeside Gas and Liquids Processing ("TGLP") terminal.

o The Company's net share of remaining capital expenditure prior to first hydrocarbons from the GSA production hub is $395 million, which will be funded from existing financial resources.

o The successful appraisal of the Hurricane discovery in Q3-2012 and the offer of Block 29/5e, adjacent to Hurricane, in the 27th UK Offshore License Round in October 2012 have further augmented the opportunity set for the GSA hub.

Hurricane

During the quarter, 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. 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 Company is in the process of completing a comprehensive work programme to assess the ultimate recoverable volumes associated with the field prior to integration of the data into the usual year end reserves evaluation that will be performed by the Company's independent reserves assessor, Sproule International Limited ("Sproule").

OTHER DEVELOPMENTS

Corporate events

In October, 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 will hold non-operated interests in UK North Sea producing fields; a 12.885% interest in the Cook field and a 14% interest in the MacCulloch field.

The acquisition will result in the Company increasing its existing Cook field interest from 28.46% to 41.345%, furthering its position as the field's largest owner. Based on the independent reserves assessment performed by Sproule, effective as of 31 December 2011, remaining net proved and probable reserves associated with the additional 12.885% interest (as of that date) are 2.0 mmboe.

The MacCulloch oil field, currently operated by ConocoPhillips, lies in Blocks 15/24b in the Central North Sea (transfer of field operatorship to Endeavour Energy UK Limited is pending completion of a previously announced transaction). The field is producing from four subsea wells tied back to the North Sea Producer FPSO, with processed oil and gas exported via pipelines to shore. Remaining net proved and probable reserves effective as of 31 December 2011 are estimated by Ithaca to be approximately 1.4 mmboe. An assessment of the field reserves will be performed by Sproule as part of the normal year end reserves evaluation exercise.

The total acquisition consideration is $38.5 million, to be funded from the Company's existing cash resources. Completion of the transactions is anticipated in early 2013 and is subject to normal regulatory and joint venture approvals, including reaching agreement in respect of decommissioning cost security.

Debt facility

In October 2012 the Company agreed and signed a $430 million Facility with BNPP as Bookrunner and Mandated Lead Arranger. The syndication process was oversubscribed, underlining the value of the Company's existing asset portfolio and development execution strategy.

The seven banks participating in the facility syndicate are:

·; BNPP and Lloyds TSB Bank plc (as Bookrunners and Mandated Arrangers);

·; Bank of America N.A., Deutsche Bank AG, The Bank of Nova Scotia and The Royal Bank of Scotland (as Mandated Lead Arrangers); and,

·; NIBC Bank N.V. (as Manager).

This Facility replaces the previous undrawn $140 million debt facility and is on similar conventional oil and gas industry borrowing base financing terms, with a loan term of up to five years. The Facility is available to fund ongoing development activities and future asset acquisitions.

27th Licensing Round

In October, Ithaca was offered two operated licenses as part of the 27th Licensing Round: Block 29/5e in the vicinity of the Company's existing GSA interests and Block 15/17b in the Outer Moray Firth. The license offers are based on the completion of technical studies, leading to a drill or drop decision on each license within two years of formal license award.

RESULTS OF OPERATIONS

Revenue

Three months ended September 30, 2012

Revenue increased by $15.2 million in Q3 2012 to $41.6 million (Q3 2011 $26.4 million). This movement mainly comprises an increase in oil sales volumes, partially offset by a small decrease in average realized oil prices and a reduction in gas sales.

Oil sales volumes increased primarily due to the inclusion of sales from the Athena field along with Broom field liftings in Q3 2012 (acquired in Q4 2011). There was a small decrease in average realized oil prices from $111.24 / bbl in Q3 2011 to $110.26 / bbl in Q3 2012 as the Brent oil price benchmark weakened during the quarter. This reduction in price was more than offset by a realized hedging gain of $2.56/bbl.

The decrease in gas sales in Q3 2012 compared to Q3 2011 was due to a reduction in Anglia and Topaz gas volumes due to maintenance shutdowns, partly offset by a small increase in the average realized gas price.

Nine months ended September 30, 2012

Revenue increased by $43.8 million in the nine months to Q3 YTD 2012 to $118.0 million (Q3 YTD 2011 $74.2 million). This movement mainly comprises an increase in oil sales volumes, partially offset by a reduction in gas sales.

The increase in oil sales volumes is primarily due to the inclusion of production from Athena, Cook and Broom fields offset by natural declines in the Beatrice and Jacky fields. The realized oil price was relatively consistent at just over $112/bbl before hedging.

The increase in oil sales was partly offset by a decrease in gas sales in the period. This was due to a reduction in Anglia and Topaz gas volumes, partially offset by the addition of Cook gas sales.

Cost of Sales

Three months ended September 30, 2012

Cost of sales increased in Q3 2012 to $27.1 million (Q3 2011 $12.7 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 period to $20.9 million (Q3 2011 $12.0 million) primarily due to the inclusion of Athena, Cook and Broom operating costs in Q3 2012 (Cook was acquired midway through Q3 2011 and Broom in Q4 2011, with Athena commencing production in Q2 2012). Operating costs per boe have increased to $44.89 for Q3 2012 (Q3 2011: $36.11) primarily driven by maintenance shutdowns in the quarter on Cook, Anglia and Topaz, along with natural declines in production on Beatrice and Jacky.

DD&A expense for the quarter increased to $14.6 million (Q3 2011 $7.9 million). This was primarily due to the addition of the Athena and Broom assets, as well as significant capital expenditure in the period from Q3 2011 to Q3 2012 leading to increased DD&A rates on existing assets. The blended DD&A rate for Q3 2012 is $31.07/boe (Q3 2011: $23.50/boe) with Athena having a positive impact which partly mitigates the increase from other fields.

An oil and gas inventory movement of $8.4 million was credited to cost of sales in Q3 2012 (Q3 2011 credit of $7.2 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 Q3 2012 more barrels of oil were produced (425k bbls) than sold (347k bbls) with volumes accounting for $8.1m 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.

Nine months ended September 30, 2012

Cost of sales increased in Q3 YTD 2012 to $83.1 million (Q3 YTD 2011 $46.4 million) due to increases in operating costs and DD&A.

Operating costs increased in the period to $52.0 million (Q3 YTD 2011 $33.8 million) primarily due to the inclusion of Athena, Cook and Broom operating costs in 2012 as noted above. Operating costs per barrel have increased to $42.73/boe in the period (Q3 YTD 2011: $41.04) due to maintenance shutdown costs coupled with natural declines in production, partially offset by the positive impact of Cook and Athena on the blended rate per barrel.

DD&A expense for the period increased to $39.0 million (Q3 YTD 2011 $19.8 million). This was primarily due to the addition of the Athena, Cook and Broom assets as well as significant capital expenditure in the period from Q3 2011 to Q3 2012 leading to increased DD&A rates on existing assets. The blended rate for the period has increased to $31.82 (Q3 YTD 2011 $23.73), with Cook and Athena having a positive impact which partly mitigates the increase from other fields.

An oil and gas inventory movement of $8.0 million was credited to cost of sales in the period (Q3 YTD 2011 credit of $7.2 million). As noted above, this is due to the build up of inventory representing the difference between barrels of oil produced and sold in the period, with more barrels being produced than sold YTD.

Administrative expenses and Exploration & Evaluation expenses

Three months ended September 30, 2012

Administrative expenses decreased in the quarter to $0.5 million (Q3 2011 $1.6 million) due to a reduction in share based payment expenses as a result of no options being granted at the end of 2011, coupled with a change in the timewriting profile, with more capitalized timewriting in Q3 2012 primarily due to increased activities on the development of the Stella and Harrier fields.

Exploration and evaluation expenses of $0.1 million were recorded in the period (Q3 2011 $0.2 million) due to the expensing of previously capitalized costs relating to areas where exploration and evaluation activities have ceased.

Nine months ended September 30, 2012

Administrative expenses decreased in the period to $3.0 million (Q3 YTD 2011 $5.2 million) again due to no options being granted at the end of 2011 and a change in the timewriting profile, with more capitalized timewriting in the nine months to September 2012.

Exploration and evaluation expenses of $0.2 million (Q3 YTD 2011 $0.2 million) were recorded in the period.

Foreign exchange and Financial Instruments

Three months ended September 30, 2012

A foreign exchange gain of $0.7 million was recorded in Q3 2012 (Q3 2011 $2.4 million loss). The majority of the Corporation's revenue is US dollar driven whilst costs 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 GBP bank accounts. This volatility was partly offset by foreign exchange hedges as described in the "Risks and Uncertainties" section below.

The Corporation recorded a $12.0 million loss on financial instruments for the three months ended September 30, 2012 (Q3 2011 $0.4 million gain). The loss was predominantly due to a $13.6 million revaluation of oil swaps and put options as a result of the September 30, 2012 oil spot price of $111.03 compared to the much lower price at June 30, 2012 of $94.50 offset by a $0.9 million realized gain on oil swaps and $0.7 million gain on the revaluation of other instruments. This loss partially reversed a gain recognized in Q2 2012 of $19.3 million as a result of the lower oil price in Q2.

Nine months ended September 30, 2012

A foreign exchange gain of $0.9 million was recorded in Q3 YTD 2012 (Q3 YTD 2011 $0.1 million gain). As above, general volatility in the USD:GBP exchange rate was the driver behind the foreign exchange gains (USD:GBP at January 1, 2012: 1.55. USD:GBP at September 30, 2012: 1.62 with fluctuations between 1.52 and 1.63 during the period).

The Corporation recorded a $6.6 million gain on financial instruments for the nine months ended September 30, 2012 (Q3 YTD 2011 $2.2 million loss). The gain was predominantly due to a $3.2 million revaluation of oil swaps and put options and a $2.6 million realized gain on commodity hedges, along with a $2.0 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

Three months ended September 30, 2012

A deferred tax credit of $2.9 million was recognized in the quarter ended September 30, 2012 (Q3 2011: less than $0.1 million credit). 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 a result of the above factors, profit after tax increased to $4.9 million (Q3 2011 $16.0 million).

Nine months ended September 30, 2012

A deferred tax credit of $10.6 million was recognized in the nine months ended September 30, 2012 (Q3 YTD 2011 $3.6 million charge). This credit is a product of adjustments to the tax charge primarily relating to the 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 a result of the above factors, profit after tax increased to $48.1 million (Q3 YTD 2011 $22.5 million).

No tax is expected to be paid in the mid-term future relating to upstream oil and gas activities.

SUMMARY OF QUARTERLY RESULTS

The following table provides a summary of the quarterly results of the Corporation for the eight most recently completed quarters:

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 has 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" below for more details.

LIQUIDITY AND CAPITAL RESOURCES

As at September 30, 2012, Ithaca had working capital of $57.9 million including a free cash balance of $56.8 million. Available cash has been, and is currently, invested in money market deposit accounts with Lloyds Banking Group ("Lloyds"). Management has received confirmation from the financial institution that these funds are available on demand. The restricted cash of $20.6 million comprises $20.5 million currently held by BNPP as decommissioning security provided as part of the acquisitions of the Anglia and Cook fields (with release / renewal dates of: February 28, 2013 ($10.9 million), and December 31, 2012 ($9.6 million)).

At September 30, 2012, Ithaca has unused credit facilities currently totalling $430 million.

During the three months ended September 30, 2012 there was a cash outflow from operating, investing and financing activities of $55.0 million (Q3 2011 outflow of $70.3 million). The net outflow was due to a cash outflow of $75.9 from investing activities, a cash outflow of $2.8 million from financing activities, partially offset by a cash inflow from operating activities of $22.8 million. The remainder of the movement was due to foreign exchange on non US Dollar denominated cash deposits. This overall free cash inflow is predominantly the product of cash generated from Athena, Beatrice, Jacky, Anglia, Topaz, Cook and Broom operations offset by development capital expenditure on the Greater Stella Area, including modification of the FPF-1, subsea design and fabrication works and appraisal well drilling on the Hurricane field.

A significant proportion of Ithaca's accounts receivable balance is with customers in the oil and gas industry and is subject to normal 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 September 30, 2012 over 99% 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.

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 undrawn debt facility. No unusual trends or fluctuations are expected outside the ordinary course of business.

COMMITMENTS

The Corporation has the following financial 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. 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

As at September 30, 2012 Ithaca had 259,346,128 common shares outstanding along with 15,276,839 options outstanding to employees and directors to acquire common shares.

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 the first, second and third years from the effective date of grant. A number of officers and employees also exercised 573,875 options at a price of C$1.80 per share in October.

As at November 9, 2012, Ithaca had 259,920,003 common shares outstanding along with 20,347,964 options outstanding to employees and directors to acquire common shares.

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 Development & Production ("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.

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 September 30, 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 Q3 2012 was $nil (Q3 2011 $0.1 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 September 30, 2012 the Corporation had a loan receivable from FPF-1 Ltd, an associate of the Corporation, for $21.6 million (Q3 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. In order to mitigate the Corporation's risk to fluctuations in oil price, the Corporation has taken out a number of commodity derivatives. In April 2012, the Corporation entered into two put options: to sell 190,000 bbls of the Corporation's May 2012 - February 2013 forecast production at a fixed price of $120.50/bbl and 200,000 bbls at a fixed price of $120/bbl. In February 2012, the Corporation entered into two swap options: to sell 268,800 bbls of the Corporation's March 2012 - December 2012 forecast production at a fixed price of $121.32/bbl; and to sell 500,000 bbls of the Corporation's forecast July 2012 - June 2013 production at $113.25 / bbl.

In August 2012 the Corporation entered into further derivatives for the period October 2012 to December 2013, being swaps of 503,800 bbls of oil at a weighted average price of $108.67 and put options, at market price, for 300,300 bbls of oil at a weighted average oil price floor of $111.34 / bbl.

The Corporation is exposed to financial risks including financial market volatility, fluctuation in interest rates and various foreign exchange rates. Given the increasing development expenditure and operating costs in currencies other than the United States dollar, the Board of Directors of the Corporation has a hedging policy to mitigate foreign exchange rate risk on committed expenditure. In November 2011, the Corporation entered into a forward extra plus contract with Lloyds to hedge part of its forecast GBP 2012 operating costs, including general and administrative expenses. The hedge amounts to $4 million per month (total $48 million) at a USD:GBP rate of no worse than $1.60/£1.0 while benefiting in any improvement of the rate down to a trigger rate of $1.40/£1.00. If the trigger rate is reached in any month the conversion rate realized for that month is $1.58/£1.00.

A further risk relates to the Corporation's ability to meet the conditions precedent for a full drawdown on the Corporation's Facility with BNPP. 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 order to have access to the full amount of the Facility, however at present the Corporation believes that there are no circumstances present that result in failure to meet those tests and can therefore draw down upon its Facility.

In addition, the Facility contains the aforementioned covenants that require the Corporation to meet certain financial tests and that restrict, among other things, the ability of Ithaca to incur additional debt or dispose of assets. To the extent the cash flow from operations is ever deemed not adequate to fund Ithaca's cash requirements, external financing may be required. Lack of timely access to such additional financing, or which may not be on favorable 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. At present the Corporation believes that there are no circumstances present that result in failure to meet those certain financial tests.

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. 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. At present the Corporation believes that there are no circumstances present that would lead to selected divestment, delays to existing programs or a default relating to the Facility.

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. Management believes the 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 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.

In addition, 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 is also subject to the risks associated with owning oil and natural gas properties, including environmental risks associated with air, land and water. The Corporation takes out market insurance to mitigate many of these operational, construction and environmental risks. In all areas of the Corporation's business there is competition with entities that may have greater technical and financial resources. 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. 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.

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.

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 September 30, 2012, there were no changes in our internal control over financial reporting that occurred during the period ended September 30, 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 three months ended September 30, 2012, including required comparative information, have been prepared in accordance with IFRS and with International Accounting Standard ("IAS") 34, Interim Financial Reporting, 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 has 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. A partially 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.

FINANCIAL INSTRUMENTS AND OTHER INSTRUMENTS

All financial instruments, other than those designated as effective hedging 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 September 30, 2012.

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

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

• 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;

• 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;

• 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 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;

• 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.

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. Many of these risk factors, other specific risks, uncertainties and material assumptions are discussed in further detail throughout the AIF and in the MD&A. Readers are specifically referred to the risk factors described in the AIF under "Risk Factors" and in other documents the Corporation files from time to time with securities regulatory authorities. Copies of these documents are available without charge from Ithaca or electronically on the internet on Ithaca's SEDAR profile at www.sedar.com.

The accompanying notes on pages 7 to 25 are an integral part of the financial statements.

The accompanying notes on pages 7 to 25 are an integral part of the financial statements.

The accompanying notes on pages 7 to 25 are an integral part of the financial statements.

The accompanying notes on pages 7 to 25 are an integral part of the financial statements.1. NATURE OF OPERATIONS

Ithaca Energy Inc. (the "Corporation" or "Ithaca"), incorporated and domiciled in Alberta, Canada on 27 April 2004, is a publicly traded company involved in the exploration, development and production of oil and gas in the North Sea. The Corporation's registered office is 1600, 333 - 7th Avenue S.W., Calgary, Alberta, Canada, T2P 2Z1. As of 1 November 2011 the Corporation's shares have traded on the Toronto Stock Exchange in Canada (previously the TSX Venture Exchange). The Corporation's shares continue to trade on AIM in the United Kingdom under the symbol "IAE". Ithaca has three wholly-owned subsidiaries, Ithaca Energy (Holdings) Limited ("Ithaca Holdings"), incorporated in Bermuda, Ithaca Energy (UK) Limited ("Ithaca UK") and Ithaca Minerals (North Sea) Limited ("Ithaca Minerals"), which was acquired on 19 October 2011, both incorporated in Scotland. Ithaca also has two associates, FPU Services Limited ("FPU Services") and FPF-1 Limited ("FPF-1"), both incorporated in Jersey.

2. BASIS OF PREPARATION

These interim consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) applicable to the preparation of interim financial statements, including IAS 34 Interim Financial Reporting. These interim consolidated financial statements do not include all the necessary annual disclosures in accordance with IFRS.

The Company has elected to present all acquisitions since the IFRS transition date as business combinations in accordance with IFRS 3(R). This has resulted in a restatement of the acquisition of gas assets from GDF (in 4Q 2010) as shown in previous interim statements during 2011.

The policies applied in these condensed interim consolidated financial statements are based on IFRS issued and outstanding as of 9 November 2012, the date the Board of Directors approved the statements. Any subsequent changes to IFRS that are given effect in the Corporation's annual consolidated financial statements for the year ending 31 December 2012 could result in restatement of these interim consolidated financial statements.

The condensed interim consolidated financial statements should be read in conjunction with the Corporation's annual financial statements for the year ended 31 December 2011.

3. SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS AND ESTIMATION UNCERTAINTY

Basis of measurement

The consolidated financial statements have been prepared under the historical cost convention, except for the revaluation of certain financial assets and financial liabilities to fair value, including derivative instruments.

Basis of consolidation

The consolidated financial statements of the Corporation include the accounts of Ithaca Energy Inc. and the wholly-owned subsidiaries Ithaca Energy (UK) Ltd, Ithaca Minerals (North Sea) Ltd and Ithaca Energy (Holdings) Ltd. All inter-company transactions and balances have been eliminated on consolidation.

A subsidiary is an entity (including special purpose entities) which the Corporation controls by having the power to govern the financial and operating policies. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether Ithaca controls another entity. A subsidiary is fully consolidated from the date on which control is obtained by Ithaca and is de-consolidated from the date that control ceases.

Investments

Interests in entities over which Ithaca has significant influence, but not control or joint control, are accounted for using the equity method. Ithaca's share of equity investments is recorded in the consolidated statement of income.

Business Combinations

Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the assets acquired, equity instruments issued and liabilities incurred or assumed at the date of completion of the acquisition. Acquisition costs incurred are expensed and included in administrative expenses. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the cost of acquisition over the fair value of the Corporation's share of the identifiable net assets acquired is recorded as goodwill. If the cost of the acquisition is less than the Corporation's share of the net assets required, the difference is recognised directly in the statement of income.

Goodwill

Capitalisation

Goodwill acquired through business combinations is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised as the fair value of the Corporation's share of the identifiable net assets acquired and liabilities assumed. If this consideration is lower than the fair value of the identifiable assets acquired, the difference is recognised in the statement of income.

Impairment

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 cash generating unit ("CGU") to which the goodwill relates. Where the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognised in the statement of income. Impairment losses relating to goodwill cannot be reversed in future periods.

Foreign currency translation

Items included in the financial statements are measured using the currency of the primary economic environment in which the Corporation and its subsidiary operate (the 'functional currency'). The consolidated financial statements are presented in United States Dollars, which is the Corporation's functional and presentation currency.

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of income.

Share based payments

The Corporation has a share based payment plan as described in note 18 (c). The Corporation's proportionate share of expense is recorded in the statement of income or capitalised for all options granted in the year, with the gross increase recorded in the share based payment reserve. Compensation costs are based on the estimated fair values at the time of the grant and the expense or capitalised amount is recognised over the vesting period of the options. Upon the exercise of the stock options, consideration paid together with the amount previously recognised in the share based payment reserve is recorded as an increase in share capital. In the event that vested options expire unexercised, previously recognised compensation expense associated with such stock options is not reversed. In the event that unvested options are forfeited or expired, previously recognised compensation expense associated with the unvested portion of such stock options is reversed.

Cash and Cash Equivalents

For the purpose of cash flow statements, cash and cash equivalents include investments with an original maturity of three months or less.

Restricted Cash

Cash that is held for security for bank guarantees is reported in the balance sheet and cash flow statements separately. If the expected duration of the restriction is less than twelve months then it is shown in current assets.

Financial Instruments

All financial instruments, other than those designated as effective hedging instruments, are initially recognised at fair value in the statement of financial position. The Corporation's financial instruments consist of cash, restricted cash, accounts receivable, deposits, derivatives, accounts payable, accrued liabilities, contingent consideration and the long term liability on the Beatrice acquisition. The Corporation classifies its financial instruments into one of the following categories: held-for-trading financial assets and financial liabilities; held-to-maturity investments; loans and receivables; and other financial liabilities. All financial instruments are required to be measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.

Held-for-trading financial instruments are subsequently measured at fair value with changes in fair value recognised in net earnings. All other categories of financial instruments are measured at amortised cost using the effective interest method. Cash and cash equivalents are classified as held-for-trading and are measured at fair value. Accounts receivable are classified as loans and receivables. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as other financial liabilities. Although the Corporation does not intend to trade its derivative financial instruments, they are classified as held-for-trading for accounting purposes.

Transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability and original issue discounts on long-term debt have been included in the carrying value of the related financial asset or liability and are amortised to consolidated net earnings over the life of the financial instrument using the effective interest method.

The Corporation may designate financial instruments as a hedging instrument for accounting purposes. Hedge accounting requires the designation of a hedging relationship, including a hedged and a hedging item, identification of the risk exposure being hedged and an expectation that the hedging relationship will be highly effective throughout its term.

The Corporation assesses, both at the hedge's inception and on an ongoing basis, whether the derivative financial instruments designated as hedges are highly effective in offsetting changes in cash flows of the hedged items. The effective portion of the gains and losses on cash flow hedges is recorded in Other Comprehensive Income until the hedged transaction is recognised in net earnings. Any hedge ineffectiveness is immediately recognised in net earnings. When the hedged transaction is recognised in net earnings, the fair value of the associated cash flow hedging item is reclassified from other reserves into net earnings. Hedge accounting is discontinued on a prospective basis when the hedging relationship no longer qualifies for hedge accounting.

Analysis of the fair values of financial instruments and further details as to how they are measured are provided in notes 23 to 25.

Inventory

Inventories of materials and product inventory supplies, other than oil and gas inventories, are stated at the lower of cost and net realisable value. Cost is determined on the first-in, first-out method. Oil and gas inventories are stated at fair value less cost to sell.

Property, plant and equipment

Oil and gas expenditure - exploration and evaluation assets

Capitalisation

Pre-acquisition costs on oil and gas assets are recognised in the statement of income when incurred. Costs incurred after rights to explore have been obtained, such as geological and geophysical surveys, drilling and commercial appraisal costs and other directly attributable costs of exploration and evaluation including technical and administrative costs are capitalised as intangible exploration and evaluation ("E&E") assets.

E&E costs are not amortised prior to the conclusion of evaluation activities. At completion of evaluation activities, if technical feasibility is demonstrated and commercial reserves are discovered then, following development sanction, the carrying value of the E&E asset is reclassified as a development and production ("D&P") asset, but only after the carrying value is assessed for impairment and where appropriate its carrying value adjusted. If after completion of evaluation activities in an area, it is not possible to determine technical feasibility and commercial viability or if the legal right to explore expires or if the Corporation decides not to continue exploration and evaluation activity, then the costs of such unsuccessful exploration and evaluation is written off to the statement of income in the period the relevant events occur.

Impairment

The Corporation's oil and gas assets are analysed into cash generating units ("CGU") for impairment review purposes, with E&E asset impairment testing being performed at a grouped CGU level. The current E&E CGU consists of the Corporation's whole E&E portfolio. E&E assets are reviewed for impairment when circumstances arise which indicate that the carrying value of an E&E asset exceeds the recoverable amount. When reviewing E&E assets for impairment, the combined carrying value of the grouped CGU is compared with the grouped CGU's recoverable amount. The recoverable amount of a grouped CGU is determined as the higher of its fair value less costs to sell and value in use. Impairment losses resulting from an impairment review are written off to the Income Statement.

Oil and gas expenditure - development and production assets

Capitalisation

Costs of bringing a field into production, including the cost of facilities, wells and sub-sea equipment together with E&E assets reclassified in accordance with the above policy, are capitalised as a D&P asset. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form a single D&P asset.

Depreciation

All costs relating to a development are accumulated and not depreciated until the commencement of production. Depreciation is calculated on a unit of production basis based on the proved and probable reserves of the asset. Any re-assessment of reserves affects the depreciation rate prospectively. Significant items of plant and equipment will normally be fully depreciated over the life of the field. However, these items are assessed to consider if their useful lives differ from the expected life of the D&P asset and should this occur a different depreciation rate would be charged.

Impairment

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 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.

Non Oil and Natural Gas Operations

Computer and office equipment is recorded at cost and depreciated over its estimated useful life on a straight-line basis over three years. Furniture and fixtures are recorded at cost and depreciated over their estimated useful lives on a straight-line basis over five years.

Decommissioning liabilities

The Corporation records the present value of legal obligations associated with the retirement of long term tangible assets, such as producing well sites and processing plants, in the period in which they are incurred with a corresponding increase in the carrying amount of the related long term asset. The obligation generally arises when the asset is installed or the ground/environment is disturbed at the field location. In subsequent periods, the asset is adjusted for any changes in the estimated amount or timing of the settlement of the obligations. 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.

Contingent consideration

Contingent consideration is accounted for as a financial liability and measured at fair value at the date of acquisition with any subsequent remeasurements recognised either in the statement of income or in other comprehensive income in accordance with IAS 39.

Taxation

Current income tax

Current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amounts are those that are enacted or substantively enacted by the reporting date.

Deferred income tax

Deferred tax is recognised for all deductible temporary differences and the carry-forward of unused tax losses. Deferred tax assets and liabilities are measured using enacted or substantively enacted income tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in rates is included in earnings in the period of the enactment date. Deferred tax assets are recorded in the consolidated financial statements if realisation is considered more likely than not.

Recent accounting pronouncements

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 with early adoption permitted. The Corporation has not yet assessed the impact that the new and amended standards will have on its financial statements or whether to early adopt any of the new requirements.

Significant accounting judgements and estimation uncertainties

The preparation of financial statements in conformity with IFRS requires management to make estimates and assumptions regarding certain assets, liabilities, revenues and expenses. Such estimates must often be made based on unsettled transactions and other events and a precise determination of many assets and liabilities is dependent upon future events. Actual results may differ from estimated amounts.

The amounts recorded for depletion, depreciation of property and equipment, long-term liability, share based payment, contingent consideration, decommissioning liabilities, derivatives, warrants, and deferred taxes are based on estimates. The depreciation charge and any impairment tests are based on estimates of proved and probable reserves, production rates, prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be material.

4. REVENUE

5. COST OF SALES

The above includes 2011 business combination restatements in accordance with IFRS 3(R). Refer to note 2 for further details.

6. ADMINISTRATIVE EXPENSES

7. FINANCE COSTS

8. RESTRICTED CASH

Restricted cash of $20.6 million is held by Bank BNP Paribas ("BNPP") as decommissioning security in respect of the Corporation's interests in the Anglia and Cook fields with release dates of 28 February 2013 ($11.0 million) and 31 December 2012 ($9.6 million).

9. INVENTORY

10. EXPLORATION AND EVALUATION ASSETS

Following completion of geotechnical evaluation activity, certain licences were declared unsuccessful and certain prospects were declared non-commercial and therefore the related expenditure of $0.2 million was expensed in the three and nine months to 30 September 2012.

Disposals in the period reflect the sale of assets to Petrofac GSA Limited and Dyas UK Limited as detailed per note 11.

The above includes 2011 business combination restatements in accordance with IFRS 3(R). Refer to note 2 for further details.

11. PROPERY, PLANT AND EQUIPMENT

Disposals in the period reflect the sale of assets to Petrofac GSA Limited ("Petrofac") and Dyas UK Limited ("Dyas") on completion of the Sale and Purchase Agreements ("SPAs") relating to the Greater Stella Area.

An overall pre-tax gain on disposal of $205k is shown through the consolidated statement of income for the nine months ended 30 September 2012.

The above includes 2011 business combination restatements in accordance with IFRS 3(R). Refer to note 2 for further details.

12. GOODWILL

$1.0 million represents goodwill recognised on the acquisition of gas assets from GDF in December 2010.

13. INVESTMENT IN ASSOCIATES

Investment in associates comprises shares, acquired by Ithaca Holdings, in FPF-1 and FPU Services as part of the completion of the Greater Stella Area transactions.

14. LOAN FACILITY

On 29 June 2012, the Corporation executed a Senior Secured Borrowing Base Facility agreement (the "Facility") for up to $430 million, being provided by BNPP as Lead Arranger. The loan term is up to five years and will attract interest at LIBOR plus 3-4.5%. This Facility replaces the previous undrawn $140 million debt facility with Lloyds Banking Group.

The Corporation is subject to financial and operating covenants related to the Facility. Failure to meet the terms of one or more of these covenants may constitute an event of default as defined in the Facility agreement, potentially resulting in accelerated repayment of the debt obligations.

The Corporation is in compliance with its financial and operating covenants.

No funds were drawn down under the Facility as at 30 September 2012.

15. DECOMMISSIONING LIABILITIES

The total future decommissioning liability was calculated by management based on its net ownership interest in all wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. The Corporation uses a risk free rate of 3.9 percent (31 December 2011: 3.9 percent) and an inflation rate of 2 percent (31 December 2011: 2 percent) over the varying lives of the assets to calculate the present value of the decommissioning liabilities. These costs are expected to be incurred at various intervals over the next 15 years.

The economic life and the timing of the obligations are dependent on Government legislation, commodity price and the future production profiles of the respective production and development facilities. Note that upon the acquisition of the Beatrice Field in November 2008, the Corporation did not assume the decommissioning liabilities.

16. OTHER LONG TERM LIABILITIES

On completion of the acquisition of the Beatrice Facilities on 10 November 2008 there were 75,000 barrels of oil in an oil storage tank at the Nigg Terminal. This volume of oil is required to be in the storage tank when the Beatrice Facilities are retransferred. This volume of oil is valued at the price on the forward oil price curve at the expected date of re-transfer and discounted. The liability is subject to revaluation at each financial period end. The expected date of re-transfer is likely to be more than three years in the future.

17. CONTINGENT CONSIDERATION

The contingent consideration at the end of the period relates to the acquisition of the Stella field and is payable upon first oil.

The release of $21.9m reflects the consideration paid upon Stella and Harrier Field Development Plan approval as well as a transfer of part of the liability to Petrofac on completion of the Greater Stella Area transactions (see note 11).

18. SHARE CAPITAL

Capital Management

The Corporation's objectives when managing capital are:

- to safeguard the Corporation's ability to continue as a going concern;

- to maintain balance sheet strength and optimal capital structure, while ensuring the Corporation's strategicobjectives are met; and

- to provide an appropriate return to shareholders relative to the risk of the Corporation's underlying assets.

Capital is defined as shareholders' equity. Shareholders' equity includes share capital, share based payment reserve, warrants issued, retained earnings or deficit and other comprehensive income.

The Corporation maintains and adjusts its capital structure based on changes in economic conditions and the Corporation's planned requirements. The Board of Directors reviews the Corporation's capital structure and monitors requirements. The Corporation may adjust its capital structure by issuing new equity and/or debt, selling and/or acquiring assets, and controlling capital expenditure programs.

The Corporation monitors its capital structure using the debt-to-equity ratio and other benchmark measures at the consolidated group level.

(b) Stock options

In the quarter ended 30 September 2012, the Corporation's Board of Directors did not grant any new options.

In the quarter ended 31 March 2012, the Corporation's Board of Directors granted 400,000 options at a weighted average exercise price of $2.28 (C$2.31).

The Corporation's stock options and exercise prices are denominated in Canadian Dollars when granted. As at 30 September 30 2012, 15,276,839 stock options to purchase common shares were outstanding, having an exercise price range of $0.20 to $2.70 (C$0.25 to C$2.69) per share and a vesting period of up to 3 years in the future.

Changes to the Corporation's stock options are summarised as follows:

* The weighted average exercise price has been converted into U.S. dollars based on the foreign exchange rate in effect at the date of issuance.

The following is a summary of stock options as at 30 September 2012

The following is a summary of stock options as at 31 December 2011

(c) Share based payments

Options granted are accounted for using the fair value method. The compensation cost during the three months and nine months ended 30 September 2012 for total stock options granted was $0.8 million and $2.4 million respectively (Q3 2011: $1.6 million, Q3 YTD: $4.8 million). $0.1 million and $0.4 million were charged through the income statement for share based payment for the three and nine months ended 30 September 2012 respectively, being the Corporation's share of share based payment chargeable through the income statement. The remainder of the Corporation's share of share based payment has been capitalised. The fair value of each stock option granted was estimated at the date of grant, using the Black-Scholes option pricing model with the following assumptions:

(d) Gemini Agreement

In September 2006 Gemini Oil & Gas Fund 11 L.P. ("Gemini") provided non-recourse funding of $6 million. Further to a supplemental agreement entered into in August 2008, the loan was fully repaid. Under the supplemental agreement Gemini retained rights, under certain circumstances relating to the Athena Field, to elect to receive warrants to acquire up to 3,000,000 common shares at $3.00 per share and to receive payments connected to asset sales of interests in Athena.

On 20 September 2010, a further agreement was entered into with Gemini whereby in exchange for and in consideration of Gemini's waiver of any right to proceeds from the disposal of equity interest in the Athena discovery and in substitution for any previously awarded or agreed warrants, Ithaca Energy Inc. granted Gemini warrants to acquire up to 2,500,000 common shares in Ithaca Energy Inc. The warrants were exercised at C$2.25 per share on 3 March 2011. The agreement terminates all rights that Gemini has in respect of the Corporation's interests. The total fair value attributed to warrants issued in 2010 was $0.3 million.

19. SHARE BASED PAYMENT RESERVE

20. EARNINGS PER SHARE

The calculation of basic earnings per share is based on the profit after tax and the weighted average number of common shares in issue during the period. The calculation of diluted earnings per share is based on the profit after tax and the weighted average number of potential common shares in issue during the period.

21. TAXATION

The above includes 2011 business combination restatements in accordance with IFRS 3(R). Refer to note 2 for further details.

22. COMMITMENTS

23. FINANCIAL INSTRUMENTS

To estimate fair value of financial instruments, the Corporation uses quoted market prices when available, or industry accepted third-party models and valuation methodologies that utilise observable market data. In addition to market information, the Corporation incorporates transaction specific details that market participants would utilise in a fair value measurement, including the impact of non-performance risk. The Corporation characterises inputs used in determining fair value using a hierarchy that prioritises inputs depending on the degree to which they are observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realised or settled in a current market transaction. The three levels of the fair value hierarchy are as follows:

• Level 1 - inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 - inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market interest rates, and volatility factors, which can be observed or corroborated in the marketplace. The Corporation obtains information from sources such as the New York Mercantile Exchange and independent price publications.

• Level 3 - inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value.

In forming estimates, the Corporation utilises the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorised based upon the lowest level of input that is significant to the fair value measurement. The valuation of over-the-counter financial swaps and collars is based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. These are categorised as Level 2.

The following table presents the Corporation's material financial instruments measured at fair value for each hierarchy level as of 30 September 2012:

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