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Production & Reserves
Total production increased approximately 120% to 10,392 barrels of oil equivalent per day ("boepd") in 2013 (2012: 4,673 boepd), driven by the inclusion of production from the Valiant assets from the acquisition completion date of 19 April 2013. Total pro-forma production in 2013, reflecting inclusion of full year production from the Valiant assets, was approximately 13,000 boepd.

The Company had 2P reserves as of 31 December 2013 of 58 MMboe, as independently assessed by Sproule International Limited ("Sproule"). This represents an increase in 2P reserves of over 14% compared to end-2012 driven by the Valiant acquisition.

The 2P reserves post-tax net asset value ("NAV") discounted at 10% assessed by Sproule as at 31 December 2013 was $1,665 million, up approximately 60% on 2012.

Greater Stella Area Update
Significant progress was made on execution of the GSA development in 2013. The first two development wells were successfully drilled on the Stella field, with the strong clean-up flow test results achieved by the wells substantially de-risking the initial annualised production forecast for the field of approximately 30,000 boepd, 16,000 boepd net to Ithaca. Approximately 65% of the subsea infrastructure was installed and the dry dock related "FPF-1" floating production facility marine system works were completed and the topsides processing plant construction works commenced.

Contracts have now been awarded by the GSA co-venturers to enable the evacuation of oil from the FPF-1 directly to market via offshore loading to shuttle tankers. The dedicated export solution provides operational certainty and control over peak oil production rates, with the offshore loading infrastructure scheduled to be installed by Technip during the 2014 campaign. It is envisaged that a pipeline connection from the FPF-1 to existing oil export infrastructure will be installed later in field life in order to maximise ultimate reserves recovery.

The heavy lift operations to install the pre-assembled units and key equipment on the main deck of the FPF-1 were completed in January 2014, following close out of the necessary main deck preparation works. The primary focus of the on-going works is the topsides processing plant being installed on the vessel.

The extreme weather over recent months has hampered drilling operations across the North Sea and has resulted in delays in moving the Ensco 100 rig to the drilling location for the next two development wells. This is not scheduled to impact the availability of all four start-up wells in time for arrival of the FPF-1 on location. Drilling of the third development well commenced in March 2014.

The 2014 subsea infrastructure installation programme is scheduled to commence in April and will be completed over several campaigns during the year, culminating in the hook-up of the FPF-1 and risers upon the arrival of the vessel on location.

2014 Operations Update
2014 production guidance remains unchanged in the range of 11,000 to 13,000 boepd, approximately 95% oil. As previously guided, the anticipated schedule of 2014 production enhancement activities means that volumes are forecast to be weighted towards the second half of the year.

Total production in Q1-2014 is estimated to be approximately 9,200 boepd, 95% oil. This is in line with forecast performance for the quarter given the previously announced unplanned shutdown of the Cook field to repair the gas export compressor on the host facility. The Cook field was re-started in February, leading to average production for the Company in March of approximately 11,500 boepd.

The extreme weather over recent months has also resulted in operational delays on sidetracking the Fionn production well, increasing the overall costs of the programme. The reservoir section of the sidetrack was recently drilled, with logs identifying over 100 feet of net reservoir sand of excellent quality, consistent with previous wells on the structure. The well completion is currently being run and it is anticipated that the well will be on-stream in May 2014.

The Don NE acreage that lies adjacent to the Company's Don Southwest field has been awarded to the Company (40% working interest) by the DECC. Submission of a "Phase 1" Field Development Plan is planned to enable a production well to be drilled on the field from the existing Don Southwest facilities, potentially as early as the end of 2014.

The Company's capital investment programme in 2014 is forecast to total $350 million.

Funding
The Company extended and improved the terms of its long term senior bank debt financing facilities during 2013 following the Valiant acquisition to $710 million; the Reserve Based Lending ("RBL") facility was increased from $430 million to $610 million and a new five year $100 million corporate facility was established.

New and extended oil sales agreements were also executed during the year with BP Oil International Limited and Shell Trading International Limited, with the Shell agreement allowing the Company to receive up to $70 million of pre-payments for future crude sales to Shell. The terms of this arrangement enabled the Company to further reduce its weighted average cost of debt finance.

Peak funding prior to the start-up of Stella is anticipated to be approximately $600 million from the combined funding facilities of $780 million.

The Company has hedged approximately 2.7 million barrels of future 2014-15 oil production at a weighted average price of around $100 / bbl (approximately 30% puts / 70% swaps). Put options have also been executed to establish a net floor price of £0.58/therm (~$10/MMbtu) for approximately 200 million therms (20 billion cubic feet) of gas sales over gas year's 2015 and 2016.

Corporate
The Board of Directors has today appointed Mr Alec Carstairs as a Non-Executive Director of the Company, subject to normal regulatory approvals. Mr Carstairs is a Chartered Accountant and former Head of UK Oil and Gas Mergers and Acquisitions at Ernst & Young LLP. He has over 35 years of experience advising on international oil and gas sector transactions involving companies ranging from new start-ups to multi-national corporations. Mr Carstairs has also been appointed Chairman of the Audit Committee.

- ENDS -

Notes
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 and gas industry.

References herein to barrels of oil equivalent ("boe") are derived by converting gas to oil in the ratio of six thousand cubic feet ("Mcf") of gas to one barrel ("bbl") of oil. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy 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, utilising a conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value.

About Ithaca Energy
Ithaca Energy Inc. (TSX: IAE; LSE: IAE) is a North Sea oil and gas operator focused on the delivery of lower risk growth through the appraisal and development of UK undeveloped discoveries, the exploitation of its existing UK producing asset portfolio and a Norwegian exploration and appraisal business targeting the generation of discoveries capable of monetisation prior to development. Ithaca's strategy is centred on generating sustainable long term shareholder value by building a highly profitable 25kboe/d North Sea oil and gas company. For further information please consult the Company's website www.ithacaenergy.com.

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

Forward-looking statements
Some of the statements and information in this press release are forward-looking. Forward-looking statements and forward-looking information (collectively, "forward-looking statements") are based on the Company'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, drilling, construction times, well completion times, risks associated with operations, future capital expenditures, continued availability of financing for future capital expenditures, future acquisitions and cash flow. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. When used in this press release, the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", "target" and similar expressions, and the negatives thereof, whether used in connection with operational activities, drilling plans, production forecasts, budgetary figures, potential developments or otherwise, are intended to identify forward-looking statements. Such statements are not promises or guarantees, and are subject to 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. The Company believes that the expectations reflected in those forward-looking statements and 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 included in this press release should not be unduly relied upon. These forward-looking statements speak only as of the date of this press release. Ithaca Energy Inc. expressly disclaims any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement contained herein to reflect any change in its expectations with regard thereto or any change in events, conditions or circumstances on which any forward-looking statement is based except as required by applicable securities laws.

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

This press release contains non-International Financial Reporting Standards ("IFRS") industry benchmarks and terms, such as "netbacks" and "cashflow from operations". "Netbacks" are calculated on a per unit basis as oil, gas and natural liquids revenues (inclusive of commodity hedging gains/losses) less royalties and transportation and operating costs. Management believes that Netback is a useful supplemental measure as it provides an indication of the results generated by the principal business activities. Netbacks may not be comparable to other similarly titled measures of other companies, and accordingly Netbacks may not comparable to measures used by other companies. "Cashflow from operations" does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. The Company uses this measure to help evaluate its performance. As an indicator of the Company'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 Company considers Cashflow from operations to be a key measure as it demonstrates the Company'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.

Additional information on these and other factors that could affect Ithaca's operations and financial results are included in the Company's Management's Discussion and Analysis for the year ended December 31, 2013, and the Company's Annual Information Form for the year ended December 31, 2013 and in reports which are on file with the Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).

Additional information on these and other factors that could affect Ithaca's operations and financial results are included in the Company's Management's Discussion and Analysis for the year ended December 31, 2012, and the Company's Annual Information Form for the year ended December 31, 2012 and in reports which are on file with the Canadian securities regulatory authorities and may be accessed through the Company's profile on the SEDAR website (www.sedar.com).

2013 HIGHLIGHTS & POST YEAR END ACTIVITIES
Record financial results

• 2013 cashflow from operations increased approximately 170% to $244.1 million (2012: $90.3 million) - cashflow per share $0.81 (2012: $0.35)

• 2013 profit after tax increased 55% to $144.7 million (2012: $93.4 million) - earnings per share $0.48 (2012: $0.36)

• 2013 average realised oil price of $109/bbl (2012: $113/bbl), including realised hedging gain in the year of $1.60 / bbl

• Netback per barrel of $66/bbl (2012:$70.0/bbl)

• Solid asset base with significant capital investment in the year reflected in total assets of $1,978.7 million (2012: $933.5 million)

• Net drawn debt of $348.5 million at December 31, 2013 (zero net drawn debt at 31 December 2012), excluding the Norwegian tax rebate facility

• UK tax allowances pool of $1,083 million at year end. Norwegian tax receivable of $61.4 million

• Approximately 2.7 million barrels of future 2014/2015 oil production hedged at a weighted average price of over $100 / bbl (approximately 30% puts / 70% swaps)

• Secured floor price of £0.58/therm (~$10/MMBTU) for approximately 200 million therms (20 billion cubic feet) of gas sales over gas year's 2015 and 2016.

Step change in production delivered in 2013 as a result of the Valiant acquisition

• Total production increased by over 120% to 10,392 barrels of oil equivalent per day ("boepd") in 2013 (2012: 4,673 boepd), driven by inclusion of production from the Valiant Petroleum plc ("Valiant") assets from April 19, 2013. Total pro-forma production in 2013 was approximately 13,000 boepd, assuming a Valiant acquisition date of January 1, 2013

• 2014 production guidance unchanged in the range of 11,000 to 13,000 boepd with approximately 95% oil. The range reflects the dependency upon the timing of the various production enhancement activities being executed during the year

• Net proven and probable ("2P") reserves at end-2013 of 58 million barrels of oil equivalent ("MMboe") as independently assessed by Sproule International Limited ("Sproule"). This represents an increase in 2P reserves of approximately 14% compared to end-2012

• Net 2P reserves post-tax net asset value ("NAV") discounted at 10% assessed by Sproule of $1,665 million, up approximately 60% on 2012.

Growing shareholder value via acquisitions and organic growth

• Material broadening of the producing asset portfolio and further financial strengthening of the Company delivered in 2013 via the Valiant acquisition

• Full integration of Valiant portfolio efficiently executed during the year, with the anticipated overhead savings rapidly crystallised through removal of all operational overlaps and the successfully completed farm-out programme removing Ithaca's exposure to the three UK exploration wells transferred as a result of the acquisition

• Post year-end the Company was awarded the "Don North East" licence (40%, non-operated) that lies adjacent to its existing Dons field position by the Department of Energy and Climate Change (the "DECC"). Submission of a "Phase 1" Field Development Plan ("FDP") is planned for later this year to enable an early production well to be drilled on the licence from the existing Don Southwest facilities

Substantial progress made on execution of GSA development in 2013

• Significant progress was made on execution of the Greater Stella Area ("GSA") development during 2013. The first two development wells were drilled, approximately 65% of the subsea infrastructure was installed and the FPF-1 marine system works were completed

• The focus of the 2014 work programme is on completion of the required drilling, subsea and FPF-1 modification work programmes to enable start-up of production from the hub at the end of the year

CORPORATE STRATEGY

Ithaca Energy Inc. ("Ithaca" or the "Company") is a North Sea oil and gas operator focused on the delivery of lower risk growth through the appraisal and development of UK undeveloped discoveries, the exploitation of its existing UK producing asset portfolio and a Norwegian exploration and appraisal business centred on the generation of discoveries capable of monetisation prior to development.

The Company has a solid and diversified UK producing asset base generating significant cashflow from operations.

Ithaca's goal is to generate sustainable long term shareholder value by building a highly profitable 25kboepd North Sea oil and gas company.

Execution of the Company's strategy is focused on the following core activities:

• Maximising cashflow and production from the existing asset base.

• Delivery of lower risk development led growth through the appraisal of undeveloped discoveries.

• Delivering first hydrocarbons from the Ithaca operated GSA development.

• Monetising proven Norwegian asset reserves derived from exploration and appraisal drilling prior to the development phase.

• Continuing to grow and diversify the cashflow base by securing new producing, development and appraisal assets through targeted acquisitions and licence round participation.

• Maintaining financial strength and a clean balance sheet, supported by lower cost debt leverage.

CORPORATE ACTIVITIES

Highly accretive acquisition - materially increasing production, reserves and cashflow

Maximising shareholder value through efficient execution of the post-acquisition integration plan

"NE Don" licence award-securing Dons Area upside

VALIANT ACQUISITION

Ithaca acquired the UK Alternative Investment Market ("AIM") listed company Valiant in April 2013, paying the equivalent of $293.6 million at completion through a mixture of cash and shares. The acquisition established Ithaca as a leading mid-cap North Sea oil and gas operator, significantly enhancing the Company's existing production base and creating a highly cash generative business, with the transfer of an additional $500 million of tax allowances providing further shelter from the payment of UK tax over the medium term. The transaction also provided Ithaca with a modest operational position in Norway.

The full integration of Valiant's portfolio into the enlarged Company was efficiently and effectively executed during 2013. The significant anticipated cost synergies were rapidly crystallised through the removal of all operational and administrative overlaps. Valiant's UK office was closed within three months of the acquisition completion date, with no UK personnel transferring into the Ithaca organisation, resulting in the removal of approximately $20 million of Valiant overhead costs. Over the course of 2013, the Company also delivered upon its stated objective at the time of the acquisition; that the UK exploration commitments transferred as a result of the acquisition would be mitigated via farm-outs.

"NE DON" LICENCE AWARD

Ithaca (40% working interest) and EnQuest (60%, Operator) have been awarded a licence post year-end by the DECC for the acreage covering the majority of the former Don North East ("Don NE") field, which lies adjacent to the producing Don Southwest field in which both companies have corresponding working interest levels.

The Don NE field was previously operated by BP and ceased production in 2005. BP and its co-venturers are currently in the process of decommissioning the wells in the northern part of the Don NE licence and as such, DECC has at this time awarded a new licence over the southern area of the field.

Submission of a Phase I FDP is planned for later in 2014 to enable a production well to be drilled on the southern part of the field from the existing Don Southwest facilities, potentially as early as the end of this year. The envisaged drilling location is in an area of the field where a previous appraisal well was drilled and tested in 1982. Depending on the production performance of the well, the drilling of further production and water injection wells in this part of the field would represent a potential Phase II development plan.

Given the ability of the co-venturers to produce wells on the Don NE field via the existing Don Southwest field infrastructure, this represents crystallisation of a valuable upside that has stemmed from the acquisition of the Valiant assets. Moreover, any development activity is expected to benefit from application of the Small Field Allowance, which shelters field revenues of up to approximately $240 million (100%) from payment of the 32% Supplementary Tax charge.

Execution of "bolt-on" asset acquisition strategy

NOBLE ACQUISTION
The transaction announced in October 2012 to acquire an additional 12.885% interest in the Cook field from Noble Energy Capital Limited (a subsidiary of Noble Energy Inc., NYSE: NBL) ("Noble") was completed in February 2013. The consideration paid at completion was $37.7 million, with approximately $14 million of this payment being offset by the transfer of oil inventory awaiting offload from the host facility for the Cook field, the Anasuria floating production, storage and offloading ("FPSO") vessel. The cashflow from operations derived from the acquired equity since the completion date has already paid back the net transaction consideration, with substantial further value still clearly remaining in the field.

RESERVES
Broad 2P reserves base, weighted towards oil - 15% increase on end-2012

Material increase in 2P reserves value driven by Valiant acquisition

• At 31 December 2013 the Company's 2P reserves were 58 MMboe (~50% oil), as independently assessed by Sproule. These reserves exclude any contribution from the Don NE licence that was awarded to the Company post year-end.

• The Company's 2P reserves have increased at a compound annual growth rate of approximately 11% since the end of 2009. In line with the Company's strategy this growth has primarily been driven organically, most significantly as a result of the Stella appraisal well in 2010, and acquisitions.

• Total 2P reserves have increased by approximately 14% compared to the position at the end of 2012. The significant increase resulting from the addition of the Valiant assets has been partially offset by a revision on Athena (~1.5MMboe), relinquishments associated with Torphins (~0.4MMboe) and the previously announced planned re-transfer of the Beatrice facilities to Talisman in early 2015 (~1.0MMboe).

• 23 MMboe of the Company's total 2P reserves are associated with producing assets. This represents an increase of approximately 50% from end-2012, driven by the assets acquired from Valiant.

• The 2P reserves post-tax NAV assessed by Sproule as at 31 December 2013 increased by approximately 60% to $1,665 million on the corresponding value at the end of 2012.

• The movement in total 2P reserves between end-2012 and end-2013 is summarised in the following table, with production during the year reflecting the inclusion of the Valiant assets from the acquisition completion date of April 19, 2013.

PRODUCTION & OPERATIONS UPDATE

122% increase in annual production in 2013, with the portfolio enlarged by a further four fields

2013 PRODUCTION
Total 2013 production taking into account the Valiant acquisition from the transaction completion date of April 19, 2013 was 10,392 boepd, approximately 95% oil; a 122% increase on 2012 (2012: 4,673 boepd). Total pro-forma production over the year, including production from the Valiant assets from the start of 2013, was approximately 13,000 boepd, 95% oil.

The material increase in production delivered in 2013 was primarily attributable to the addition of the Valiant assets. This increased the Company's producing asset portfolio from seven to eleven fields, six of which are operated by Ithaca.

2014 PRODUCTION
The Company's 2014 net production is anticipated to be in the range of 11,000 to 13,000 boepd, approximately 95% oil. The range reflects the dependency upon the timing of the various production enhancement activities being executed during the year. No production from the GSA hub is incorporated in the range.

As previously announced, the anticipated schedule of 2014 production enhancement activities means that volumes are forecast to be weighted towards the second half of the year. More specifically, the guidance highlighted that production during the first quarter would be below the full year range driven primarily by an unplanned shutdown of the Cook field to repair the gas export compressor on the host facility for the field.

Ahead of closing out the final allocation data for the month of March, total production in Q1-2014 is estimated to be approximately 9,200 boepd, 95% oil. This is in line with forecast performance for the quarter given the Cook shutdown, a planned shutdown of the Beatrice Area facilities to complete certain inspection and maintenance works and to a more limited extent, the impact of the historically extreme weather conditions that have impacted North Sea operations over the period. The Cook field was re-started in February, leading to average production for the month of March of approximately 11,500 boepd.

Operations remain on-track to achieve 2014 production guidance of 11-13kboe/d

OPERATIONS UPDATE
The key production enhancement activities that are to be delivered over the balance of 2014 are:

• Completion of the Fionn production well sidetrack

• Start-up of electrical submersible pumps ("ESPs") on the Causeway and Fionn fields

• Start-up of water injection on the Causeway field

• Drilling of an infill well on the Don Southwest field

• Workover of the "P4" well on the Athena field

Causeway Area
The previously reported harsh weather that impacted drilling operations on the Fionn sidetrack over the turn of the year continued to delay execution of the work programme throughout Q1-2014, increasing the overall costs of the programme. The reservoir section of the sidetrack has been completed, with logs identifying over 100 feet of net reservoir sand of excellent quality, consistent with previous wells on the structure. The well completion is currently being run and it is anticipated that the well will be on-stream in May 2014.

Hook-up and commissioning activities continue on the Taqa-operated platform facilities that are required to enable the start-up of ESP support for the Causeway and Fionn production wells. The works remain on-track for the ESPs to be operational later in second quarter of 2014. The platform modifications also being completed by Taqa to enable the start-up of water injection on the Causeway field are similarly progressing for start-up in approximately the same timeframe.

Dons
The Don Southwest co-venturers have awarded a contract for use of the Ocean Princess semi-submersible rig for drilling of the planned infill well on the field. The well is expected onstream around in the third quarter of the year.

Athena
The Athena co-venturers are finalising execution of a rig contract in order to perform the planned "P4" well workover to replace the failed ESP package in the well during the second half of the year.

Beatrice / Jacky
As previously announced, it is anticipated that 2014 will be the last year of production from the Beatrice area facilities. Under the terms of the Beatrice facilities lease agreement executed with Talisman in 2008, Ithaca is able to re-transfer the facilities to Talisman for decommissioning. Preparation for the re-transfer is underway.

GREATER STELLA AREA DEVELOPMENT UPDATE
Substantial progress made to enable start-up of the hub at the end of 2014

Ithaca's focus on the GSA is driven by the monetisation of over 30MMboe of net 2P reserves within the existing portfolio and the generation of additional value via the wider opportunities provided by the range of undeveloped discoveries surrounding the production hub.

The development involves the creation of a production hub based on deployment of the FPF-1 floating production facility located over the Stella field, with onward export of oil and gas. To maximise initial oil and condensate production and fill the gas processing facilities on the FPF-1, four Stella wells are planned for the start-up of production from the hub; three in the oil-rim and one crestal gas condensate producer. Further wells on Stella and Harrier, plus other potential targets, including Hurricane, will then be drilled post first hydrocarbons from Stella to maintain the gas processing facilities on plateau.

Contracts awarded for oil exports from the hub via offshore loading

OIL EXPORT
The GSA co-venturers have concluded the optimal initial oil export solution for the production hub should be the evacuation of oil directly to market via offshore loading to shuttle tankers. This will provide operational certainty and control over peak oil production rates. It is envisaged that a pipeline connection from the FPF-1 to existing oil export infrastructure will be installed later in field life, in order to maximise ultimate reserves recovery.

The offshore loading solution will involve oil being exported from the FPF-1 directly into shuttle tankers via a Single Point Loading ("SPL") system. A contract has been awarded to APL Norway AS (subsidiary of National Oilwell Varco Inc.) for fabrication of the SPL buoy and a contract of affreightment has been executed with Teekay for the provision of shuttle tankers. The associated subsea infrastructure will be installed by Technip during the 2014 offshore campaign.

Dry dock related marine works completed in 2013, topsides processing plant installation activities on-going

Heavy lifts associated with main pre-assembled units and racks completed

FPF-1 MODIFICATION WORKS
The focus of the FPF-1 modification programme during 2013 was on completion of the dry dock related marine system refurbishment / hull life extension works and the commencement of the main topsides processing plant construction and installation activities.

The dry dock related marine system works were completed in October 2013. Three additional sponsons have been added to the pontoons on the FPF-1, involving the construction and installation of approximately 2000 tonnes of steelwork blocks, to provide enhanced buoyancy. Four buoyancy "blisters" are being added to the columns of the FPF-1 in parallel with the topsides construction works. These modifications are to ensure that the FPF-1 can accommodate the new topsides processing equipment that is to be installed on the main deck and achieve strong operational uptime performance.

With the vessel back in the water in the fourth quarter of 2013, the core focus of the modifications programme transferred to completion of the workscopes on the main deck of the vessel. Preparation of the main deck for the installation of the pre-assembled units that had been constructed alongside the vessel in the latter part of 2013 was completed in January 2014, along with the heavy lift operations to install the units and other key equipment on the main deck.

In 2014 the modifications programme is focused on completion of the planned construction and onshore commissioning activities required to enable the vessel to sail to the field. The forecast duration of these works indicates first hydrocarbons from the GSA hub will be at the end of 2014.

Execution of the FPF-1 modifications work programme is being performed by Petrofac under the terms of a lump sum incentivised contract with the GSA co-venturers.

Two of the four Stella start-up wells successfully drilled and tested, third well on-going

DRILLING PROGRAMME
The Stella development drilling campaign commenced in late June 2013 using the Ensco 100 heavy duty jack-up rig, with the first two of the four start-up development wells that are to be drilled on the field being completed in January 2014. Clean-up flow tests were performed on the wells in order to suspend them ready for immediate production once the FPF-1 is on location and hooked up and also to gain additional reservoir data and fluid samples. Each of the wells individually flowed at over 10,000 boepd (60-70% oil), with the rates being constrained by the test equipment on the drilling rig. These results substantially de-risk the initial annualised production forecast for the field of approximately 30,000 boepd (100%), 16,000 boepd net to Ithaca.

Since finishing the suspension operations on the "A2" well in January 2014, historically extreme weather delayed the commencement of drilling on the third Stella field development well; the sea state required to enable the jack-up rig to be towed from the drilling location of the first two wells to the northern drilling centre was substantially and consistently outside permissible levels. The rig move was ultimately completed in March 2014 and drilling operations are currently on-going in the 20-inch section of the well.

Both the third and fourth Stella development wells will be drilled from the rig's current location, thus no further rig moves will be required to complete the start-up well programme. The delay in commencement of drilling operations on the third well is not scheduled to impact the availability of all four start-up wells in time for the arrival of the FPF-1 on location.

Management of the drilling and completion operations is being performed by Applied Drilling Technology International ("ADTI") under "turnkey" contract arrangements.

~65% of subsea infrastructure installed, including main heavy lifts - 2014 campaign scheduled to recommence in April 2014

SUBSEA INFRASTRUCTURE WORKS
The 2013 subsea infrastructure installation programme was successfully closed out in November 2013. The main subsea structures for the production and export of hydrocarbons (the manifolds and riser bases), the 60km gas export pipeline and the infield flowlines and umbilicals have all been installed and the associated diver tie-in works completed during the 2013 campaign. This means that approximately 65% of the overall subsea work programme required to deliver first hydrocarbons has now been completed; corresponding to a total of over 220 vessel days in 2013.

The key outstanding workscopes to be completed during 2014 involve the tie-in of the wells, installation of the dynamic flexible risers and umbilicals that will connect the riser bases to the FPF-1, the vessel mooring spread and the oil export facilities. The 2014 programme is scheduled to commence in April and be completed over several campaigns, culminating in the hook-up of the FPF-1 and risers upon the arrival of the vessel on location.

Execution of the main subsea infrastructure manufacturing and installation programme is being completed by Technip under an integrated Engineering, Procurement, Installation and Construction contract.

PORTFOLIO MANAGEMENT
Restructuring of former Valiant portfolio rapidly completed, establishing a fully carried position to drill-out UK exploration well commitments

Licence management activities during 2013 have been focused on restructuring the portfolio acquired as a result of the Valiant acquisition.

• Most significantly, farm‐outs of the three former Valiant UK exploration well commitments (Handcross, Beverley and Isabella) resulted in Ithaca establishing a fully carried position, collectively, for the forecast cost of drilling the wells and in addition received cash from the farm-out parties. In overall terms, the agreements resulted in Ithaca removing net UK exploration expenditure commitments of approximately $85 million.

• A re-focused strategy has been established for the Norwegian business acquired from Valiant, centred on the generation of discoveries in lower risk geological / geographic settings that are capable of monetisation prior to development.

• Restructuring of the Norwegian portfolio since the acquisition means that the Company has exited the Barents Sea, most significantly swapping its position in the "Langlitinden" well for a licence interest in the Norwegian North Sea with Tullow Norge AS, on which a well is scheduled to be drilled on the "Lupus" prospect in mid-2014. A farm-in executed with TOTAL E&P Norge AS resulted in an oil discovery close to existing infrastructure being made on the "Trell" prospect in early 2014. Non-operated positions in two Norwegian North Sea licences were also awarded to the Company in the 2013 APA licence round.

• Ithaca and Dyas UK Limited ("Dyas") entered into an agreement with North Sea Energy Limited ("NSE") to remove NSE from the Jacky joint venture in March 2014. As a result, Ithaca increased its interest in the Jacky field from 47.5% to 52.5% and is putting in place a cost sharing agreement with Dyas to share all costs 50/50 (excluding decommissioning and related costs).

DRILLING ACTIVITY
The following two wells that were transferred as part of the Valiant acquisition were drilled over the last 12 months.

• Handcross (UK): Following completion of the successful Handcross exploration well farm-out programme in 2013, which resulted in Ithaca achieving a full carry for its share of the well cost, the required commitment well was drilled on the prospect in early 2014. No hydrocarbons were encountered by the well in the target formation. The Company had recorded a liability provision in its financial accounts for the cost of the well upon completion of the Valiant acquisition.

• Norvarg (Norway): An appraisal well was drilled and tested on the Norvarg appraisal well in mid-2013. Further analysis of the well results by the Operator, TOTAL E&P Norge AS, has indicated that despite the considerable extent of the discovery and the presence of mobile gas in the Kobe formation, the reservoir properties and lack of infrastructure in the area means that Norvarg is considered non-commercial at this time. The full year accounts reflect a net $3 million write-off associated with the well ($13 million pre-tax offset by a $10 million tax refund from the Norwegian government).

FINANCE ACTIVITIES

Enlarged senior debt facility established, along with a new corporate debt facility

DEBT FACILITY
The Company's existing Reserve Based Lending facility (the "RBL Facility") was enlarged to $610 million in October 2013 in order to incorporate the assets acquired as part of the Valiant acquisition and enable retirement of the $350 million bridge credit facility taken out earlier in the year to facilitate the acquisition. The RBL Facility is based on conventional oil and gas industry borrowing base financing terms, with an interest rate of 2.75-3.0% over US Libor and a loan term until June 2017. The RBL Facility is available to fund on‐going development activities and any producing asset acquisitions.

A new $100 million five year corporate debt facility was also put in place in October 2013, providing additional financial flexibility for the Company. This facility is based on normal corporate debt covenants, relating to EBITDAX ("Earnings before Interest Tax Depreciation, Amortisation and Exploration costs") coverage of debt and interest obligations, and an interest rate of 4.1% over US Libor.

Oil sales agreements covering enlarged production portfolio executed, incorporating attractive pre-payment option

OIL SALES AGREEMENTS
The Company entered into an extension of its existing agreement with BP Oil International Limited for the marketing of niche grade crudes and its oil sales agreement with Shell Trading International Limited ("Shell") for production from the Cook, Dons, Causeway Area and Broom producing fields. Future volumes from the Stella field may also be included. This latter agreement includes the ability for Ithaca, at its option, to receive up to $70 million pre-payments for future crude sales to Shell. The interest cost of any pre-payments advanced is 3% per annum, thereby reducing the aggregate blended rate of debt available to the Company. No commitment fees are payable on non-utilisation.

Additional commodity hedging executed to establish a robust floor to medium term cashflows

COMMODITY HEDGING
Oil Hedging

• 3.6 million barrels of oil production over the next 2 years hedged at over $100/bbl (70% swaps / 30% puts). This hedging underpins approximately $360 million of revenue (net of all hedging costs) while retaining oil price upside on over a third of the hedged volume.

Gas Hedging

• Secured floor price of £0.58/therm (~$10/MMBTU) for approximately 200 million therms (20 Bcf) of gas sales over gas year's 2015 and 2016. This hedging underpins approximately $200 million of revenue (net of all hedging costs) while retaining full upside to rising gas prices beyond £0.63/therm.

BOARD OF DIRECTORS

Board of Directors expanded with addition of highly experienced oil and gas industry professionals

On October 1, 2013 Mr Les Thomas replaced Mr Iain McKendrick as Chief Executive Officer and Executive Board Director of the Company. Mr Thomas has over 30 years of experience in the oil and gas industry, most recently serving as an Executive Board Director and Chief Executive of John Wood Group plc's ("Wood Group") Production Facilities business. Prior to this, Mr Thomas worked for 22 years at Marathon Oil, latterly as European Business Unit Leader responsible for the company's upstream business in the UK, Ireland, the Netherlands and Norway.

On 30 May 2013 Mr Jannik Lindbæk was appointed as a Non-Executive Director of the Company. Mr Lindbæk has a wealth of oil and gas industry experience, having previously held the position of Chairman of the Norwegian international oil and gas company Statoil ASA prior to its merger with Norsk Hydro in 2007, in addition to also previously having been Chairman of Den Norske Bank ASA and Saga Petroleum ASA.

On 31 March 2014 the Board of Directors appointed Mr Alec Carstairs as a Non-Executive Director of the Company. Mr Carstairs is a Chartered Accountant and former Head of UK Oil and Gas Mergers and Acquisitions at Ernst & Young LLP. He has over 35 years of experience advising on oil and gas sector transactions involving companies ranging from new start-ups to multi-national corporations.

In relation to Mr Carstairs appointment to the Board of Directors, the Company confirms that there is no further information to be disclosed under paragraph (g) of Schedule 2 of the AIM Rules for Companies save as disclosed below:

Full Name: Alexander Marshall Carstairs
Age: 57
Current Directorships / Partnerships in the last 5 Years:
Cela Consulting Limited
Aberdeen & Grampian Chamber of Commerce
Vine Trust
Previous Directorships / Partnerships in the last 5 Years:
N/A

SELECTED ANNUAL INFORMATION

Financial Highlights

• Revenue growth through increased production from the corporate acquisition of Valiant and the increased equity interest in Cook, as well as a full year's production from the Athena field

• Record Earnings per Share

• Total assets increased mainly as a result of the Valiant acquisition and significant capital investment in the GSA development

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

*Weighted average number of shares

2013 RESULTS OF OPERATIONS

REVENUE
Record annual revenue of $414 million, a 143% increase on 2012

Revenue increased by $243.4 million in 2013 to $413.9million (2012: $170.5 million). This was mainly driven by an increase in oil sales volumes coupled with a marginal increase in gas sales.

Oil sales volumes increased primarily due to the inclusion of sales from the Dons and Causeway fields following the acquisition of Valiant. Production from the additional Cook field interest acquired from Noble (transaction completed in Q1 2013) and a full year's production contribution from the Athena field also added to the increase in oil sales, marginally offset by lower volumes from the Beatrice and Jacky fields.

The increase in gas sales in 2013 compared to 2012 was due to a higher realised price together with increased Cook volumes, partially offset by a reduction in Anglia and Topaz gas volumes.

There was a small decrease in average realized oil prices from $110.15/bbl in 2012 to $107.28/bbl in 2013. The average Brent price for the year ended 2013 was $108.82/bbl compared to $111.75 for 2012. The Company's realized oil prices do not strictly follow the Brent price pattern given the various oil sales contracts in place, with some fields sold at a discount or premium to Brent. This decrease in realized oil price was nonetheless partially offset by a realized hedging gain of $1.60/bbl in the year.

COST OF SALES

Cost of sales increased in 2013 to $327.0 million (2012: $135.0 million) due to higher production volumes resulting in increases in operating costs and depletion, depreciation and amortization ("DD&A") and movement in oil and gas inventory.

Operating costs increased in the year to $149.8million (2012: $85.5 million) primarily due to the inclusion of costs for the Dons and Causeway fields acquired from Valiant, plus increased Athena costs (only part period in 2012) and the additional interest in the Cook field acquired from Noble.

Operating costs decreased to $39.49/boe in the year (2012: $49.74) mainly as a result of the inclusion of the lower cost Dons and Causeway fields acquired from Valiant.

DD&A expense for the year increased to $158.3 million (2012: $56.2 million). This was primarily due to higher production volumes in 2013 with the addition of the Dons and Causeway fields, together with a full period of production from the Athena field and the additional interest in the Cook field. The blended rate for the year has increased to $41.62/boe (2012: $32.45/boe).

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

An oil and gas inventory movement of $17.9 million was charged to cost of sales in 2013 (2012 credit of $6.6 million). Movements in oil inventory arise due to differences between barrels produced and sold with production being recorded as a credit to movement in oil inventory through cost of sales until oil has been sold. In 2013 more barrels of oil were sold (3,741k bbls) than produced (3,579k bbls), mainly as a result of the timing of Cook, Causeway and Dons field liftings.

* Due to long term inventory transfers and terminal quality adjustments

ADMINISTRATION & EXPLORATION & EVALUATION EXPENSES

Total administrative expenses increased in the year to $10.7 million (2012: $5.2 million) primarily due to an increase in general and administrative expenses as a result of the continued growth of the Company. Around $3 million of the G&A cost relates to the costs of the new Norwegian office, however, approximately $2 million is recovered as a cash tax refund from the Norwegian government - the credit is recorded under Taxation. Share based payment expenses decreased as a result of fewer options being granted during 2013 (smaller tranche of options granted October 2013 compared to December 2012), therefore reduced amortisation expense throughout 2013, as well as a change in the cost distribution based on the timewriting profile with a higher proportion of costs capitalised in 2013.

Valiant acquisition costs of $10.2 million were incurred in the year with approximately half of the costs relating to advisory fees and the other half to restructuring costs. The post-acquisition restructuring was completed during the year, with Valiant's UK office closed and new management appointed in Norway.

Exploration and evaluation expenses of $18.7 million were recorded in the year (2012: $4.3 million) primarily due to the decision not to pursue the development of the Norvarg discovery after detailed commercial and technical review (approximately $13 million). It should be noted that approximately $11m is recoverable as a cash tax refund from the Norwegian government. The remainder relates to other E&E prospects, which were deemed uncommercial and therefore the related expenditure was expensed.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

A foreign exchange gain of $1.0 million was recorded in 2013 (2012: $1.0 million gain). The majority of the Company's revenue is US dollar driven while expenditures are incurred in British pounds, US dollars and Euros. General volatility in the USD:GBP exchange rate is the primary driver behind the foreign exchange gains and losses, particularly on the revaluation of the GBP bank accounts (USD:GBP at January 1, 2013: 1.62. USD:GBP at December 31, 2013: 1.65 with fluctuation between 1.48 and 1.65 during the year).

The Company recorded an overall $21.7 million loss on financial instruments for the year ended December 31, 2013 (2012: $6.7 million gain). A $12.9 million gain was realised in respect of instruments which expired during the year - $6.0 million realised gain on commodity hedges and a $6.9 million realised gain on foreign exchange instruments. Offsetting the gain was the revaluation of instruments at December 31, 2013 which relates to instruments still held at year end. This $34.9 million non-cash revaluation primarily related to a downwards revaluation of commodity hedges due to a reduction in value of oil swaps and put options based on the movement in the Brent oil forward curve and the implied volatility at the end of the reporting period. The Company does not apply hedge accounting, which can therefore lead to volatility in the results due to the impact of revaluing the financial instruments at each reporting period end. The Brent spot price closed relatively high at $110 at December 31, 2013 resulting in a mark-to-market loss on commodity hedges which were entered into to ensure prices of over $100/bbl were obtained.

BUSINESS COMBINATIONS

NEGATIVE GOODWILL
If the cost of an acquisition is more than the fair value of net assets acquired, the difference is recognised on the balance sheet as goodwill. Conversely, if the cost of an acquisition is less than the fair value of the assets acquired, the difference is recognised as negative goodwill in the statement of income. As a result of business combination accounting for the Valiant acquisition, $54.4 million of negative goodwill was recognised in 2013. In addition, $0.9 million negative goodwill was recognised in

Q1 2013 in relation to the Cook acquisition totalling negative goodwill of $55.3 million in the year ended December 31, 2013.

EXPLORATION OBLIGATION
As part of the Valiant acquisition accounting, a liability was created to cover committed exploration expenditure. On the farm-out of Handcross to Euroil Exploration Limited, RWE Dea, Oyster Petroleum Limited and Sussex Energy Limited, the full Handcross liability was released and credited to the statement of income to reflect the fact that Ithaca will no longer be liable for these costs. The Isabella exploration obligation was also fully released post farm out to Euroil Exploration Limited. The remaining liability on the balance sheet is anticipated to cover other acquired future committed exploration expenditure.

TAXATION

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

A tax credit of $104.5 million was recognized in the year ended December 31, 2013 (2012: $64.2 million credit). $94.4 million is a non-cash credit relating to UK taxation and is a product of adjustments to the tax charge primarily relating to: the available SFA, a tax shelter against the 32% supplemental tax charge applicable to the Athena, Causeway and Fionn fields; UK Ring Fence Expenditure Supplement; share based payments; and relief claimed for the reinvestment of disposal proceeds relating to the sale of assets to Petrofac GSA Limited and Dyas UK Limited. As noted in the Cost Of Sales section the deferred tax credit is increased by the use of accounting for acquisitions as business combinations.

The remaining $10.1 million credit is due to Norwegian tax refunds, which have been generated as a result of exploration expenditure, incurred by Ithaca's Norwegian operations during 2013. Further Norwegian tax refunds totalling $61.4 million relate to Norwegian capital expenditure and are recognised on the balance sheet.

As a result of the above factors, profit after tax increased to $144.7 million (2012: $93.4 million).

No tax is expected to be paid in the mid-term future relating to upstream oil and gas activities as a result of the $1,083 million of UK tax losses available to the Company.

CAPITAL INVESTMENTS

$615 million of the total $1,018 million capital additions to development and production ("D&P") assets in 2013 was attributable to the fair value on acquisition of the Valiant producing fields resulting from business combination accounting (the total acquisition cost being $293.6 million). A further $28 million reflects non-cash additions to decommissioning liabilities predominantly relating to the Stella field. The remaining D&P additions of $375 million relate primarily to the acquisition of the additional interest in the Cook field and execution of the GSA development, with the main areas of expenditure being on the manufacture and fabrication of subsea infrastructure and execution of the FPF-1 modification works (as described above).

Capital expenditure on E&E assets in 2013 was $60.1 million, offset by a $31.2million release of the acquired E&E liability, resulting in a net addition of $29 million. Expenditure was primarily focused on the Norvarg exploration and appraisal well in Norway as well as UK pre-development projects. As part of the Valiant acquisition accounting, a liability was created to cover the committed exploration spend along with a corresponding asset for the associated Norwegian tax credit receivable. This liability is released as the expenditure is incurred, essentially resulting in a nil asset value within PP&E.

LIQUIDITY AND CAPITAL RESOURCES
Significant investment in development projects

*Working capital being total current assets less trade and other payables

As at December 31, 2013, Ithaca had a net credit working capital balance of $26 million including a free cash balance of $63.4 million ($12.2 million restricted cash). Available cash has been, and is currently, invested in money market deposit accounts with BNP Paribas. Management has received confirmation from the financial institution that these funds are available on demand.

Cash and cash equivalents increased as a result of bank debt drawings towards the end of the fourth quarter offsetting the continued cash investment in the ongoing Stella field development. The funds were drawn for substantial payments due for imminent release post December 31, 2013 on the Stella development. Other working capital movements are driven by the timing of receipts and payments of balances.

A significant proportion of Ithaca's accounts receivable balance is with customers and co-venturers in the oil and gas industry and is subject to normal joint venture/ industry credit risks. The Company assesses partners' credit worthiness before entering into joint venture agreements. The Company regularly monitors all customer receivable balances outstanding in excess of 90 days. As at December 31, 2013 substantially all of the accounts receivable is current, being defined as less than 90 days. In the past, the Company has not experienced credit loss in the collection of accounts receivable.

At December 31, 2013, Ithaca had two UK loan facilities available, being the $610 million RBL Facility and the $100 million corporate debt facility. At year end, the Company had unused UK credit facilities totalling approximately $300 million (Q4 2012: $430 million), with approximately $410 million drawn under the Facility.

Additionally, the Company also has a Norwegian tax refund facility (the "Norwegian Facility") of NOK 450 million (~$75 million), under which approximately $34 million was drawn as at December 31, 2013.

During the year ended December 31, 2013 there was a cash inflow from operating, investing and financing activities of approximately $32 million (2012 outflow of $64.0 million).

Cashflow from operations
Cash generated from operating activities was $244 million primarily due to cash generated from Athena, Beatrice, Jacky, Anglia, Cook and Broom operations, augmented in 2013 primarily due to the inclusion of Dons and Causeway operations.

Cashflow from financing activities
Cash generated from financing activities was $293 million primarily due to the drawdown of the existing debt facilities in 2013 ($329 million net).

Cashflow from investing activities
Cash used in investing activities was $592 million. $200 million of this related to the cash consideration paid on the Valiant acquisition as well as further capital expenditure on the GSA development, relating to drilling, FPF-1 modification works and subsea infrastructure construction and installation activities.

The Company continues to be fully funded, with more than sufficient financial resources to cover its anticipated future commitments from its existing cash balance, debt facilities and forecast cashflow from operations. No unusual trends or fluctuations are expected outside the ordinary course of business. The debt position at December 31, 2013 was low given the high levels of working capital on the balance sheet, which are expected to mainly unwind over the course of Q1-2014.

COMMITMENTS

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

Q4-2013 FINANCIAL RESULTS

Oil and gas sales revenue increased from $52.6 million in Q4 2012 to $111.7 million in Q4 2013. The increase was predominantly due to the inclusion of sales from the Dons and Causeway fields following the acquisition of Valiant. Gas volumes were up on the same period in 2012, however, this was offset by lower realised prices ($38/boe in Q4 2013 compared to $44/boe in Q4 2012).

Cost of sales increased to $91.1 million in Q4 2013 (Q4 2012: $52.0 million). The main driver behind the increase was the rise in DD&A, primarily due to the addition of the Dons and Causeway fields acquired from Valiant, plus the additional acquired interest in the Cook field. The blended rate for the quarter increased from $34/boe in Q4 2012 to $44/boe in 2013 primarily due to the accounting for the acquisition. In addition, operating costs increased, again due to the addition of the former Valiant assets and the additional Cook interest as well as the maturing Beatrice and Jacky fields incurring higher maintenance and servicing costs.

The most significant factors to have affected the Company's results during the above quarters, other than transactions such as the Valiant acquisition, are fluctuations in underlying commodity prices and movement in production volumes. The Company 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.

OUTSTANDING SHARE INFORMATION

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

As at December 31, 2013 Ithaca had 323,633,620 common shares outstanding along with 14,593,567 options outstanding to employees and directors to acquire common shares.

In 2013, the Company's Board of Directors granted 1,820,232 options at a weighted average exercise price of C$2.50. Each of the options granted may be exercised over a period of four years from the grant date. One third of the options will vest at the end of each of the first, second and third years from the effective date of grant.

Due to the exercise and listing of option shares following the end of Q4-2013, as at March 28, 2014, Ithaca had 326,548,621 common shares outstanding along with 18,843,566 options outstanding to employees and directors to acquire common shares.

(1) Represents the TSX close price (CAD$2.67) on December 31, 2013. US$:CAD$ 0.93 on December 31, 2013

CONSOLIDATION

The consolidated financial statements of the Company and the financial data contained in this management's discussion and analysis ("MD&A") are prepared in accordance with IFRS.

The consolidated financial statements include the accounts of Ithaca and its wholly‐owned subsidiaries Ithaca Energy (Holdings) Limited ("Ithaca Holdings"), Ithaca Energy (UK) Limited ("Ithaca UK"), Ithaca Minerals North Sea Limited ("Ithaca Minerals") and Ithaca Energy Holdings (UK) Limited ("Ithaca Holdings UK") and its associates FPU Services Limited ("FPU") and FPF‐1 Limited ("FPF‐1").

The consolidated financial statements also include, from April 19, 2013 only (being the acquisition date)
the Valiant group of companies, comprising the following companies:

• Ithaca Petroleum Limited (formerly Valiant Petroleum plc)

• Ithaca Causeway Limited (formerly Valiant Causeway Limited)

• Ithaca Exploration Limited (formerly Valiant Exploration Limited)

• Ithaca Alpha (NI) Limited (formerly Valiant Alpha (NI) Limited

• Ithaca Gamma Limited (formerly Valiant Gamma Limited)

• Ithaca Epsilon Limited (formerly Valiant Epsilon Limited)

• Ithaca Delta Limited (formerly Valiant Delta Limited)

• Ithaca Petroleum Holdings AS (formerly Valiant Petroleum Holdings AS)

• Ithaca Petroleum Norge AS (formerly Valiant Petroleum Norge AS)

• Ithaca Technology AS (formerly Valiant Technology AS)

• Ithaca AS (formerly Querqus AS)

• Ithaca Petroleum EHF (formerly Valiant Petroleum EHF)

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

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 Company 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 Company 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 Company's D&P assets may be impaired. For D&P assets where there are such indications, an impairment test is carried out on the Cash Generating Unit ("CGU"). Each CGU is identified in accordance with IAS 36. The Company'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 Company'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 Company 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 Company'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 Company must estimate capital expenditures on capital projects that are in progress or recently completed where actual costs have not been received as of the reporting date.

CONTROL ENVIRONMENT

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

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

As of December 31, 2013, there were no changes in our internal control over financial reporting that occurred during the year ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

CHANGES IN ACCOUNTING POLICIES

On January 1, 2011, the Company adopted IFRS using a transition date of January 1, 2010. The financial statements for the year ended December 31, 2013, including required comparative information, have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("IASB").

The Company elected to present all acquisitions since the IFRS transition date as business combinations in accordance with IFRS 3®.

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

In May 2011, the IASB issued the following standards: IFRS 10, Consolidated Financial Statements ("IFRS 10"), IFRS 11, Joint Arrangements ("IFRS 11"), IFRS 12, Disclosure of Interests in Other Entities ("IFRS 12"), IAS 27, Separate Financial Statements ("IAS 27"), IFRS 13, Fair Value Measurement ("IFRS 13") and amended IAS 28, Investments in Associates and Joint Ventures ("IAS 28"). Each of the new standards is effective for annual periods beginning on or after 1 January 2013. There has been no material impact from the adoption of the new and amended standards on the Company's financial statements.

ADDITIONAL INFORMATION
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 Company uses this measure to help evaluate its performance. As an indicator of the Company'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 Company considers Cashflow from operations to be a key measure as it demonstrates the Company'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.

'EBITDAX' referred to in this MD&A is not prescribed by IFRS. EBITDAX is defined as earnings before Interest, Taxes, Depreciation, Amortisation, and Exploration costs. EBITDAX is a supplemental non-GAAP financial measure that is not recognised under IFRS and does not have a standardized meaning prescribed by IFRS. EBITDAX should not be considered as an alternative to, or more meaningful than, net profit and comprehensive income or cash flows from operating activities as determined in accordance with IFRS or as an indicator of operating performance or liquidity. The computations of EBITDAX may not be comparable to other similarly titled measures of other companies, and accordingly EBITDAX may not be comparable to measures used by other companies.

'Netbacks' referred to in this MD&A is not prescribed by IFRS. Netbacks are calculated on a per unit basis as oil, gas and natural liquids revenues (inclusive of commodity hedging gains/losses) less royalties and transportation and operating costs. Management believes that Netback is a useful supplemental measure as it provides an indication of the results generated by the principal business activities. Netbacks may not be comparable to other similarly titled measures of other companies, and accordingly Netbacks may not be comparable to measures used by other companies.

'Net working capital' referred to in this MD&A is not prescribed by IFRS. Net working capital includes total current assets less trade & other payables. Net working capital may not be comparable to other similarly titled measures of other companies, and accordingly Net working capital may not be comparable to measures used by other companies.

Off Balance Sheet Arrangements

The Company has certain lease agreements and rig commitments which were entered into in the normal course of operations, all of which are disclosed under the heading "Commitments", above. Leases are treated as either operating leases or finance leases based on the extent to which risks and rewards incidental to ownership lie with the lessor or the lessee under IAS 17. No asset or liability value has been assigned to any leases on the balance sheet as at December 31, 2013.

Related Party Transactions

A director of the Company is a partner of Burstall Winger LLP who acts as counsel for the Company. The amount of fees paid to Burstall Winger LLP in 2013 was $0.5 million (2012: $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 December 31, 2013 the Company had a loan receivable from FPF-1 Ltd, an associate of the Company, for $31.6 million (2012:21.6 million) as a result of the completion of the GSA transactions.

BOE Presentation

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

Well Test Results

Certain well test results disclosed in this MD&A represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery there from.

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 Company's internal expectations, estimates, projections, assumptions and beliefs as at the date of such statements or information, including, among other things, assumptions with respect to production, future capital expenditures, future acquisitions and cash flow. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", "scheduled", "targeted", "approximately" and similar expressions are intended to identify forward-looking statements and forward-looking information. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. The Company 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 Company 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 Company'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 Company's ability to raise capital;

• The continued availability of the Facilities;

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

• The realization of anticipated benefits from acquisitions and dispositions;

• The Company's ability to continually add to reserves;

• Schedules and timing of certain projects and the Company's strategy for growth;

• The Company's future operating and financial results;

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

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

• Production rates;

• The ability of the company to continue operating in the face of inclement weather;

• Targeted production levels; and

• Timing and cost of the development of the Company's reserves.

With respect to forward-looking statements contained in this MD&A and any documents incorporated by reference herein, the Company 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 Company's development plan for the Stella and Harrier discoveries will be implemented as planned;

• The Company's ability to keep operating during periods of harsh weather;

• 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 Company's ability to access the Facilities;

• The continued ability of the Company to collect amounts receivable from third parties who Ithaca has provided credit to;

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

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

The Company'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 risks of inclement weather and the unavailability of 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 Company to fund its substantial capital requirements and operations;

• Risks associated with ensuring title to the Company's properties;

• Changes in environmental, health and safety or other legislation applicable to the Company's operations, and the Company'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 Company's exploration and development drilling and estimated decline rates;

• The Company's success at acquisition, exploration, exploitation and development of reserves;

• Risks associated with realisation of anticipated benefits of acquisitions;

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

• The Company's reliance on key operational and management personnel;

• The ability of the Company 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 or Norwegian taxes;

• Adverse regulatory rulings, orders and decisions; and

• Risks associated with the nature of the common shares.

Additional Reader Advisories

The information in this MD&A is provided as of March 28, 2014. The 2013 results have been compared to the results of 2012. This MD&A should be read in conjunction with the Company's consolidated financial statements as at December 31, 2013 and 2012 together with the accompanying notes and Annual Information Form ("AIF") for the year ended December 31, 2013. Copies of these documents are available without charge from Ithaca or electronically on the internet on Ithaca's SEDAR profile at www.sedar.com.

With respect to Ithaca's reserves disclosure, the figures are derived from a report prepared by Sproule, an independent qualified reserves evaluator, evaluating the reserves of Ithaca as of December 31, 2013 and forming the basis for the Statement of Reserves Data and Other Oil and Gas information of Ithaca dated March 19, 2014 (the "Statement"). The reserves for the South West Heather field included in the Statement are those estimated by the Company and reviewed by Sproule.

The reserves estimates of Ithaca are based on the Canadian Oil and Gas Evaluation Handbook ("COGEH") pursuant to Canadian National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities, with references to oil referring to medium quality oil.

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

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

General Information

Directors
Jack C. Lee (Chairman)
Les Thomas (Chief Executive) (appointed 1 October 2013)
Iain McKendrick (Chief Executive) (resigned 1 October 2013)
John Patrick Summers
Frank Wormsbecker
Jay Zammit
Ron Brenneman
Brad Hurtubise
Jannik Linbaeck (appointed 30 May 2013)

Company Secretary
Pinsent Masons Secretarial Limited
1 Park Row
Leeds
LS1 5AB

Independent Auditors
PricewaterhouseCoopers LLP
Chartered Accountants and Statutory Auditors
32 Albyn Place
Aberdeen
AB10 1YL

Bankers
BNP Paribas
London Office
40 Harewood Avenue
London
NW1 6AA

Solicitors
Pinsent Masons
13 Queen's Road
Aberdeen
AB15 4YL

Registered Office
1600, 333 - 7th Avenue S.W.
Calgary
Alberta
Canada
T2P 2Z1

Independent Auditors' Report

To the Shareholders of Ithaca Energy Inc.

We have audited the accompanying consolidated financial statements of Ithaca Energy Inc and its subsidiaries, which comprise the Statement of Financial Position as at 31 December 2013 and 31 December 2012 and the consolidated Statement of Income, Statement of Changes in Equity and Statement of Cash Flow for the years then ended, and the related notes, which comprise a summary of significant accounting policies and other explanatory information.

Management's responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

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

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Ithaca Energy Inc and its subsidiaries as at 31 December 2013 and 31 December 2012 and their financial performance and their cash flows for the years then ended in accordance with International Financial Reporting Standards.

Chartered Accountants

"PricewaterhouseCoopers LLP"

PricewaterhouseCoopers LLP
32 Albyn Place
Aberdeen
AB10 1YL
28 March 2014

No separate statement of comprehensive income has been prepared as all such gains and losses have been incorporated in the consolidated statement of income above.

The results above are entirely derived from continuing operations.

The notes on pages 8 to 28 are an integral part of these consolidated financial statements.

The notes on pages 8 to 28 are an integral part of these consolidated financial statements.

Consolidated Statement of Changes in Equity

The notes on pages 8 to 28 are an integral part of these consolidated financial statements.

Consolidated Statement of Cash Flow

The accompanying notes on pages 8 to 28 are an integral part of the financial statements.

Note to the consolidated 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. The Corporation's shares trade on the Toronto Stock Exchange in Canada and the London Stock Exchange's Alternative Investment Market in the United Kingdom under the symbol "IAE".

The consolidated financial statements of Ithaca Energy Inc. for the year ended 31 December 2013 were authorised for issue in accordance with a resolution of the directors on 28 March 2014.

2. BASIS OF PREPARATION

The Corporation prepares its financial statements in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

The consolidated financial statements are presented in US dollars and all values are rounded to the nearest thousand (US$ 000), except when otherwise indicated.

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 (under IFRS) to fair value, including derivative instruments.

Basis of consolidation

The consolidated financial statements of the Corporation include the accounts of Ithaca Energy Inc. and all wholly-owned subsidiaries. Ithaca has seventeen wholly-owned subsidiaries, thirteen of which were acquired on 19 April 2013 as part of the acquisition of Valiant Petroleum PLC ("Valiant"). The consolidated financial statements include the Valiant group of companies from 19 April 2013 only (being the acquisition date). All inter-company transactions and balances have been eliminated on consolidation.

A subsidiary is an entity 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.

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 acquired, the difference is recognised directly in the statement of income as negative goodwill.

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.

Interest in joint arrangements and associates

Under IFRS 11, joint arrangements are those that convey joint control which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. Investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. Associates are investments over which the Corporation has significant influence but not control or joint control, and generally holds between 20% and 50% of the voting rights.

Under the equity method, investments are carried at cost plus post-acquisition changes in the Corporation's share of net assets, less any impairment in value in individual investments. The consolidated income statement reflects the Corporation's share of the results and operations after tax and interest.

The Corporation's interest in joint operations (eg exploration and production arrangements) are accounted for by recognising its assets (including its share of assets held jointly), its liabilities (including its share of liabilities incurred jointly), its revenue from the sale of its share of the output arising from the joint operation, its share of revenue from the sale of output by the joint operation and its expenses (including its share of any expenses incurred jointly).

Revenue

Oil, gas and condensate revenues associated with the sale of the Corporation's crude oil and natural gas are recognised when title passes to the customer. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. Revenues from the production of oil and natural gas properties in which the Corporation has an interest with joint venture partners are recognised on the basis of the Corporation's working interest in those properties (the entitlement method). Differences between the production sold and the Corporation's share of production are recognised within cost of sales at market value.

Interest income is recognised on an accruals basis and is separately recorded on the face of the statement of income.

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 subsidiaries 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 23 (c). The expense is recorded in the consolidated 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 share based compensation 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 the statement of cash flow, 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 statement of financial position and statement of cash flow 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 on 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 acquired as part of the Beatrice field 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.

Analyses of the fair values of financial instruments and further details as to how they are measured are provided in notes 28 to 30.

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.

Trade receivables

Trade receivables are recognised and carried at the original invoiced amount, less any provision for estimated irrecoverable amounts.

Trade payables

Trade payables are measured at cost.

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 consolidated 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, administrative and share based payment expenses 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 are 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 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 statement of income.

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, direct costs including staff costs and share based payment expense 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.

Borrowing costs

All interest-bearing loans and other borrowings with banks are initially recognised at fair value net of directly attributable transaction costs. After initial recognition, interest-bearing loans and other borrowings are subsequently measured at amortised cost using the effective interest method. Amortised cost is calculated by taking into account any issue costs, discount or premium.

Loan origination fees are capitalised and amortised over the term of the loan. Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets until such time as the assets are substantially ready for their intended use of sale. All other borrowing costs are expensed as incurred.

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 profit or loss 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.

Deferred tax assets and liabilities are offset only when a legally enforceable right of offset exists and the deferred tax assets and liabilities arose in the same tax jurisdiction.

Operating leases

Rentals under operating leases are charged to the statement of income on a straight line basis over the period of the lease.

Maintenance expenditure

Expenditure on major maintenance refits or repairs is capitalised where it enhances the life or performance of an asset above its originally assessed standard of performance; replaces an asset or part of an asset which was separately depreciated and which is then written off, or restores the economic benefits of an asset which has been fully depreciated. All other maintenance expenditure is charged to the statement of income as incurred.

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. There has been no material impact from the adoption of the new and amended standards on the Corporation's financial statements.

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, and deferred taxes are based on estimates. The depreciation charge, any impairment tests and fair value estimates for the purpose of purchase price allocation (business combinations) 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. Further information on each of these estimates is included within the notes to the financial statements.

4. SEGMENTAL REPORTING

The Company operates a single class of business being oil and gas exploration, development and production and related activities in a single geographical area presently being Europe.

5. REVENUE

6. COST OF SALES

7. ADMINISTRATIVE EXPENSES

Staff costs above are recharged to joint venture partners or capitalised to the extent that they are directly attributable to capital projects.

8. FINANCE COSTS

9. RESTRICTED CASH

The above represents cash backed letters of credit for SVT tariff agreements at 31 December 2013.

10. ACCOUNTS RECEIVABLE

11. INVENTORY

12. EXPLORATION AND EVALUATION ASSETS

Following completion of geotechnical evaluation activity, certain licences were declared unsuccessful and certain prospects were declared non-commercial. Therefore, the related expenditure of $18.7 million was expensed in the 12 months to 31 December 2013, $13 million of which relates to the write off of Norvarg.

The above also includes the release of the exploration obligation provision against expenditure incurred (see note 19).

13. PROPERY, PLANT AND EQUIPMENT

Impairment charges in the year reflect the full write off of the Beatrice and Jacky fields which management determined have reached the end of their economic life. This is primarily due to rising anticipated future operating costs as well as the expected cessation of production from the Beatrice area facilities and expected re-transfer of the facilities to Talisman for decommissioning in early 2015.

14. BUSINESS COMBINATIONS

Valiant Acquisition

On 19 April 2013 the Corporation completed the acquisition of Valiant Petroleum PLC ("Valiant"). The total acquisition consideration was $293.6 million, being $200.6 million paid in cash and $93 million paid with Ithaca shares. The consolidated financial statements include the results of Valiant from the acquisition date.

The Valiant acquisition has established Ithaca as a leading mid-cap North Sea oil and gas operator. The transaction has significantly enhanced the Company's existing production base and producing asset reserves, establishing a highly cash generative business, with tax allowances sheltering the Company from the payment of UK tax over the medium term, and provided operational entry into Norway.

The Valiant acquisition has been accounted for as a business combination in accordance with IFRS 3.

The fair values of the identifiable assets and liabilities of Valiant as at the acquisition date were reassessed during the year to reflect additional information which has become available concerning conditions that existed at the date of acquisition in accordance with the provisions of IFRS 3 - Business Combinations. The final acquisition fair values of the identifiable assets and liabilities are set out below, including retrospective adjustments to the previously reported fair values. To the extent that the aggregate fair value of the identifiable assets and liabilities exceeds the purchase consideration of the Valiant assets, negative goodwill has been recognised in the consolidated statement of income for the year.

From the date of acquisition, Valiant has contributed $176.7 million of revenue and approximately $49 million to the net profit before tax. If the combination had taken place at the beginning of the year, the contribution to profit before tax for the period would have been approximately $84 million and the contribution to revenue would have been $288.2 million. Note profit before tax excludes negative goodwill.

Acquisition related costs of $10.2 million have been charged to administrative expenses in the consolidated statement of income for the year ended 31 December 2013.

Cook Acquisition

On 5 February 2013 the Company completed the acquisition of wholly-owned UK subsidiary of Noble Energy Capital Limited, which owns a 12.885% non-operated interest in the Cook field (increasing the Company's field interest in Cook to 41.345%). The total acquisition consideration was $37.7 million.

The fair values of the identifiable assets and liabilities of Cook as at the acquisition date were:

From the date of acquisition, the Cook acquisition has contributed approximately $39 million of revenue and approximately $6 million to the net profit before tax. If the combination had taken place at the beginning of the year, the contribution to profit before tax for the period would have been approximately $7 million and the contribution to revenue would have been $41 million. Note profit before tax excludes negative goodwill.

15. GOODWILL

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

As at 31 December 2013, the recoverable amount of assets acquired from GDF was sufficiently high to support the carrying value of this goodwill.

16. INVESTMENT IN ASSOCIATES

Investment in associates comprises shares, acquired by Ithaca Energy (Holdings) Limited, in FPF-1 Limited and FPU Services Limited as part of the completion of the Greater Stella Area transactions in 2012. There has been no change in value during the period with the above investment reflecting the Company's share of the associates' results.

17. BORROWINGS

On 29 June 2012, the Corporation executed a Reserves Based Lending Facility agreement (the "RBL Facility") for up to $430 million, being provided by BNPP as Lead Arranger. The loan term was up to five years and attracted interest at LIBOR plus 3-4.5%.

The Corporation also executed a $350 million bridge loan (the "Bridge Facility") in April 2013 with BNP Paribas, the Bank of Nova Scotia and Bank of America Merrill Lynch. The Bridge Facility was available for 12 months and attracted interest of LIBOR plus 1.0 - 2.25%.

In October 2013, the Corporation increased its existing RBL Facility to $610 million with enhanced terms including reduced margin costs (LIBOR plus 2.75%-3%) and greater flexibility over future unallocated capital with a loan term until June 2017. This enabled retirement of the aforementioned $350 million Bridge Facility.

The Corporation also established a new five year $100 million corporate facility in October 2013 with a term of up to 5 years which attracts interest at LIBOR plus 4.15%.

On 1 July 2013, the Corporation signed a NOK 450 million (approximately $75 million) Norwegian Exploration Financing Facility (the "Norwegian Facility") with a loan term of 1 year. Under the Norwegian tax regime, 78% of exploration, appraisal and supporting expenditure resulting from operations on the Norwegian Continental Shelf is refunded by the Government in the December of the year following the year the costs were incurred. This is a conventional tax refund facility on industry standard terms.

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

Security provided against the loan

Security provided against the facilities is in the form of a floating charge over all assets of the Ithaca group.

As at 31 December 2013, $410 million was drawn down under the RBL Facility and approximately $34 million was drawn under the Norwegian Facility. $12 million of loan fees have been capitalised.

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

18. TRADE AND OTHER PAYABLES

19. EXPLORATION OBLIGATIONS

The above reflects the fair value of E&E commitments assumed as part of the Valiant transaction. During the year to 31 December 2013, $59.7 million was released reflecting expenditure incurred in the period ($31.2 million) as well as the release of the Handcross and Isabella obligations post farm-outs ($28.5 million). An additional gain on disposal of $1.5 million was recorded in the consolidated statement of income.

20. 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 3.0 percent (31 December 2012: 3.8 percent) and an inflation rate of 2.0 percent (31 December 2012: 2.1 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 14 years.

Additions in the period primarily relate to the acquisition of Valiant ($82 million) and the development of Stella. Revisions are the result of changes in cost estimates as well as timing and discount rate changes.

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.

21. OTHER LONG-TERM LIABILITIES

The above balance relates to volumes of oil at the Nigg terminal which must be settled on re-transfer to Talisman, expected to take place in early 2015.

22. 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.

23. SHARE CAPITAL

The share issue in the period reflects shares issued as part consideration for the Valiant acquisition in April 2013.

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 and net debt. 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 31 December 2013, the Corporation's Board of Directors granted 1,730,232 options at an exercise price of $2.46 (C$2.53).

In the quarter ended 31 March 2013, the Corporation's Board of Directors granted 90,000 options at a weighted average exercise price of $2.00 (C$1.97).

The Corporation's stock options and exercise prices are denominated in Canadian Dollars when granted. As at 31 December 2013, 14,593,567 stock options to purchase common shares were outstanding, having an exercise price range of $0.20 to $2.46 (C$0.25 to C$2.53) per share and a vesting period of up to 4 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 31 December 2013

The following is a summary of stock options as at 31 December 2012

(c) Share based payments

Options granted are accounted for using the fair value method. The compensation cost during the year ended 31 December 2013 for total stock options granted was $3.7 million (2012: $3.8 million). $0.6 million was charged through the statement of income for share based payment for the year ended 31 December 2013 (2012: $0.9 million), being the Corporation's share, after cut back to joint venture partners, of share based payment chargeable through the statement of income. 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:

24. SHARE BASED PAYMENT RESERVE

25. 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.

26. TAXATION

The tax on the group's profit before tax differs from the theoretical amount that would arise using the effective rate of tax applicable for UK ring fence oil and gas activities as follows:

The effective rate of tax applicable for UK ring fence oil and gas activities in 2013 was 62% (2012: 62%).

A current tax receivable arises in respect of Norway operations.

The deferred tax effect of small field allowance in respect of the Causeway and Fionn fields has been recognised in 2013, in addition to the previously recognised small field allowance on Stella and Athena. This will reduce part of the future tax liability on these fields from a total rate of 62% to 30%. Ithaca has recognised this allowance based on the assessment that the fields will generate sufficient profits to utilise the allowance.

Deferred income tax at 31 December relates to the following:

The gross movement on the deferred income tax account is as follows:

Deferred income tax assets are recognised for the carry-forward of unused tax losses and unused tax credits to the extent that it is probable that taxable profits will be available in the future against which the unused tax losses/credits can be utilised.

The UK related tax losses of $1,083 million do not expire under UK tax legislation and may be carried forward indefinitely.

Based on current production and price assumptions and a continuing business model whereby the Corporation reinvests capital, incurs general, administrative and interest costs, together with the non-capital losses available to the Corporation, Ithaca does not expect to pay trade related cash income taxes in the short or medium term.

27. COMMITMENTS

28. FINANCIAL INSTRUMENTS

To estimate the 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 31 December 2013:

Assets measured at fair value in the statement of financial position are minimal. Measurement was based on oil price at the time of acquisition.

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

The Corporation has identified that it is exposed principally to these areas of market risk.

i) Commodity Risk

The table below presents the total gain/ (loss) on commodity hedges that has been disclosed through the consolidated statement of income:

Commodity price risk related to crude oil prices is the Corporation's most significant market risk exposure. Crude oil prices and quality differentials are influenced by worldwide factors such as OPEC actions, political events and supply and demand fundamentals. The Corporation is also exposed to natural gas price movements on uncontracted gas sales. Natural gas prices, in addition to the worldwide factors noted above, can also be influenced by local market conditions. The Corporation's expenditures are subject to the effects of inflation, and prices received for the product sold are not readily adjustable to cover any increase in expenses from inflation. The Corporation may periodically use different types of derivative instruments to manage its exposure to price volatility, thus mitigating fluctuations in commodity-related cash flows.

The below represents commodity hedges in place:

ii) Interest Risk

Calculation of interest payments for the RBL Facility agreement incorporates LIBOR whilst the Norwegian Facility incorporates NIBOR. The Corporation is therefore exposed to interest rate risk to the extent that LIBOR/NIBOR may fluctuate. The below represents interest rate financial instruments in place:

iii) Foreign Exchange Rate Risk

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

The Corporation is exposed to foreign exchange risks to the extent it transacts in various currencies, while measuring and reporting its results in US Dollars. Since time passes between the recording of a receivable or payable transaction and its collection or payment, the Corporation is exposed to gains or losses on non-USD amounts and on statement of financial position translation of monetary accounts denominated in non-USD amounts upon spot rate fluctuations from quarter to quarter.

The below represents foreign exchange financial instruments in place:

iv) Credit Risk

The Corporation's accounts receivable with customers in the oil and gas industry are subject to normal industry credit risks and are unsecured. All of its oil production from the Beatrice, Jacky and Athena fields is sold to BP Oil International Limited. Oil production from Cook, Broom, Dons, Causeway and Fionn is sold to Shell Trading International Ltd. Anglia and Topaz gas production is currently sold through two 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 assesses partners' credit worthiness before entering into farm-in or joint venture agreements. In the past, the Corporation has not experienced credit loss in the collection of accounts receivable. As the Corporation's exploration, drilling and development activities expand with existing and new joint venture partners, the Corporation will assess and continuously update its management of associated credit risk and related procedures.

The Corporation regularly monitors all customer receivable balances outstanding in excess of 90 days. As at 31 December 2013 substantially all accounts receivables are current, being defined as less than 90 days. The Corporation has no allowance for doubtful accounts as at 31 December 2013 (31 December 2012: $Nil).

The Corporation may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The Corporation's exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date. As at 31 December 2013, exposure is $5.1 million (31 December 2012: $8.3 million).

The Corporation also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The maximum credit exposure associated with financial assets is the carrying values.

v) Liquidity Risk

Liquidity risk includes the risk that as a result of its operational liquidity requirements the Corporation will not have sufficient funds to settle a transaction on the due date. The Corporation manages liquidity risk by maintaining adequate cash reserves, banking facilities, and by considering medium and future requirements by continuously monitoring forecast and actual cash flows. The Corporation considers the maturity profiles of its financial assets and liabilities. As at 31 December 2013, substantially all accounts payable are current.

The following table shows the timing of contractual cash outflows relating to trade and other payables.

29. DERIVATIVE FINANCIAL INSTRUMENTS

Refer to note 28 for details of derivative financial instruments.

30. FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES

Financial instruments of the Corporation consist mainly of cash and cash equivalents, receivables, payables, loans and financial derivative contracts, all of which are included in these financial statements. At 31 December 2013, the classification of financial instruments and the carrying amounts reported on the statement of financial position and their estimated fair values are as follows:

31. RELATED PARTY TRANSACTIONS

The consolidated financial statements include the financial statements of Ithaca Energy Inc and the subsidiaries listed in the following table:

Transactions between subsidiaries are eliminated on consolidation.

The following table provides the total amount of transactions that have been entered into with related parties during the year ending 31 December 2013 and 31 December 2012, as well as balances with related parties as of 31 December 2013 and 31 December 2012:

A director of the Corporation is a partner of Burstall Winger LLP who acts as counsel for the Corporation.

Key management compensation

Key management includes the Chief Executive Officer, the Chief Financial Officer, the Chief Development Officer, the Chief Technical Officer, the Chief Production Officer and the Non-Executive Directors. The compensation paid or payable to key management for employee services is shown below:

Share based payment reflects the value of options granted in 2013 as per the Black Scholes option pricing model. This does not represent a cash payment to key management personnel.

27. INTEREST IN JOINTLY CONTROLLED ASSETS

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