IAE.L Regulatory News (IAE)

Ithaca Energy

Les Thomas

lthomas@ithacaenergy.com

+44 (0)1224 650 261

Graham Forbes

gforbes@ithacaenergy.com

+44 (0)1224 652 151

Richard Smith

rsmith@ithacaenergy.com

+44 (0)1224 652 172

FTI Consulting

Edward Westropp

edward.westropp@fticonsulting.com

+44 (0)207 269 7230

Shannon Brushe

shannon.brushe@fticonsulting.com

+44 (0)203 727 1077

Cenkos Securities

Neil McDonald

nmcdonald@cenkos.com

+44 (0)207 397 8900

Nick Tulloch

ntulloch@cenkos.com

+44 (0)131 220 6939

RBC Capital Markets

Daniel Conti

daniel.conti@rbccm.com

+44 (0)207 653 4000

Matthew Coakes

matthew.coakes@rbccm.com

+44 (0)207 653 4000

2014 HIGHLIGHTS

Solid underlying cashflow generation despite sharp decline in oil price in H2-2014

· $181.5 million1 underlying cashflow from operations in 2014 (2013: $241.1 million) - underlying cashflow per share $0.55 (2013: $0.80)

· Loss after tax of $24.5 million in 2014 reflecting non-cash post-tax impairments of $173 million due to lower near term oil price assumptions (2013: profit of $144.7 million)

· 2014 average realised oil price of $100/bbl (2013: $109/bbl), including a realised hedging gain in the year of $3/bbl

· Net drawn debt of $763.3 million at 31 December 2014 ($348.5 million at 31 December 2013), excluding the Norwegian tax rebate facility

· UK tax allowances pool of $1,496 million at 31 December 2014 (2013: $1,083 million). Norwegian tax receivable of $32.4 million (2013: $61.4 million)

Strong reserves growth delivered in 2014

· Ithaca acquired interests in three non-operated UK oil fields in 2014, further broadening the producing asset base with the addition of high quality, long-life oil assets with clear upsides

· Total proved and probable ("2P") reserves at 31 December 2014 of 70.5 million barrels of oil equivalent ("MMboe"), as independently assessed by Sproule International Limited ("Sproule"), representing a year on year increase in 2P reserves of approximately 22%

· 2P reserves post-tax net asset value discounted at 10% of $1,744 million independently assessed by Sproule, up approximately 5% on 2013 despite the fall in commodity prices

Increasing production trend - significant hedging protection against further oil price weakness

· 2014 production of 10,947 barrels of oil equivalent per day ("boepd"), a 5% increase on the previous year (2013: 10,392 boepd)

· 2015 production guidance of approximately 12,000 boepd, 95% oil. Over 12,500 boepd forecast for Q1-2015 in line with guidance

· Unit operating expenditure set to fall to under $40/boe in 2015 with scope for further reductions before additional step down with the start-up of production from the Stella field

· 8,300 bopd hedged at $91/bbl from January 2015 to June 2016 - $80 million of cash gain from the hedges realised in Q1-2015 through acceleration of a portion of the value

· 4,000 bopd hedged at $69/bbl from July 2016 to June 2017

Balance sheet strength underpinned by solid hedged position through to mid-2017

· Diversified debt capital structure established in 2014 through the issuance of $300 million five year unsecured senior notes - augmenting the existing $610 million reserves based lending ("RBL") facility and $100 million corporate facility

· Peak net drawn debt prior to Stella start-up anticipated to be approximately $850 million in the second quarter of 2015 - approximately $780 million forecast net drawn debt at 31 March 2015

· Full funding to Stella first oil forecast within existing $1,010 million finance facilities - in the process of extending the bank debt facilities to the third quarter of 2018

· With the benefit of the significant volume of oil hedges in place, the Company has a Brent breakeven price for the existing producing asset base of under $10/bbl until Stella start-up in addition to having received approximately an $80 million cash gain from hedging in Q1-2015

Substantial progress made on execution of GSA development in 2014 - production start-up now scheduled for Q2-2016

· Material de-risking of Greater Stella Area development delivered in 2014 despite the start-up timing delayed to Q2-2016 - overall development programme is highly advanced and strong clean-up flow test results from first four Stella wells de-risk initial annualised production of 30,000 boepd (100%), 16,000 boepd net to Ithaca

· Development drilling programme close to completion, with encouraging data obtained from final Stella Ekofisk chalk reservoir well ahead of performing planned clean-up flow test in April 2015

· Strong alignment between all parties for delivery of Stella first hydrocarbons in line with revised schedule, with added confidence provided by the incentivised "FPF-1" mechanical completion schedule agreed between Petrofac and the Remontowa yard

SUMMARY STATEMENT OF INCOME

(1) Average realized price before hedging

(2) Revenue excluding other income

(3) Inventory movement excluding oil stock revaluation

(4) 2014 Opex net of forex gains, other income (Nigg cost contribution) and 2013 Sullom Voe Terminal ("SVT") charge

(5) 2014 underlying cashflow from operations excl. $12M late 2013 SVT charge and oil stock revaluation of $16.3M

SUMMARY BALANCE SHEET

Note this table shows debt repayable as opposed to the reported balance sheet debt which nets off capitalised RBL and senior note costs

(1) Net drawn debt excludes the Norwegian Tax Rebate Facility which is considered as a tax advance underwritten and off-set by a receivable from the Norwegian government

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.

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.

· Delivering first hydrocarbons from the Ithaca operated GSA development.

· Delivery of lower risk, long term development led growth through the appraisal of undeveloped discoveries.

· 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 capital discipline, financial strength and a clean balance sheet, supported by lower cost debt leverage.

CORPORATE ACTIVITIES

Further broadening of the producing asset base delivered through the assets acquired from Sumitomo Corporation

SUMMIT ACQUISITION

In 2014 Ithaca acquired interests in three non-operated UK producing oil fields from Sumitomo Corporation. The transaction, effective as of 1 January 2014, completed on 31 July 2014 for a net consideration of $163 million. The acquisition delivered further diversification of the Company's producing asset base with the addition of high quality, long-life oil assets with clear upsides, and enables acceleration in the monetisation of existing UK tax allowances. The acquired assets comprised: a further 20% interest in the Cook field in which the Company already had a 41.346% interest; a 7.48% interest in the Pierce field; and, a 7.43% interest in the Wytch Farm field.

Debt funding diversity and interest rate certainty introduced to the capital structure through the issuance of $300M senior unsecured notes

SENIOR NOTES ISSUANCE

The Company seeks to maintain a conservative financial profile and strong balance sheet with ample liquidity in order to prudently deliver its planned development activities and the long term growth of the business. To this end, in July 2014 the Company successfully completed an offering of $300 million 8.125% senior unsecured notes due July 2019, with interest payable semi-annually. The net proceeds of the notes were used to partially repay (without cancelling) the Company's RBL facility, with a portion of it subsequently redrawn to finance the acquisition of the Summit Assets on 31 July 2014.

The senior notes have provided important diversity to the sources and tenor of funding within the overall capital structure of the business and have a strong fit with the Company's long term appraisal and development growth focus. The notes reduce bank funding dependency, which represents a significant advantage in the current Brent price environment, and provide cost of finance certainty through the fixed rate coupon.

DIRECTOR & EXECUTIVE CHANGES

In 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 with over 35 years of experience advising on oil and gas sector transactions. Mr Carstairs is chairman of the Company's Audit Committee, having replaced Mr John Summers who retired from the Board of Directors in June 2014.

As part of restructuring the organisation, certain senior management changes have been made since the start of the year. Mr Roy Buchan joined the Company as Chief Operations Officer in January 2015. Mr Mike Travis has transferred from the role of Chief Production Officer to Stella Asset Manager and Mr John Woods, previously Chief Developments Officer, has left the Company.

PRODUCTION & OPERATIONS

5% increase in annual production delivered in 2014

Good progressed achieved with completion of planned 2015 operational activities during the first quarter

Q1-2015 production performance in line with guidance

Operating expenditure savings being realised through supply chain contract renegotiations and removal of overheads

Material Athena field cost reduction secured via revised FPSO contract terms

2014 PRODUCTION & OPERATIONS

Average 2014 production was 10,947 boepd, 95% oil (2013: 10,392 boepd), reflecting inclusion of production from the Summit Assets from the acquisition completion date of 31 July 2014.

Year on year production increased by approximately 5%. The increase was driven by inclusion of a full year's contribution from Valiant Petroleum plc ("Valiant") assets acquired in April 2013 and the contribution of various production enhancement activities undertaken during the year, which more than offset the reduction in volumes attributable to host facility driven unplanned shutdowns on the Cook field at the start of 2014 and the Causeway Area fields in the second half of the year in addition to natural field decline rates. Production from the Jacky field ceased in the fourth quarter of 2014 and the Beatrice field at the turn of the year as part of preparing for the planned re-transfer of the Beatrice facilities to Talisman for decommissioning. The re-transfer was completed in Q1-2015.

2015 PRODUCTION & OPERATIONS

Production in 2015 is forecast to average approximately 12,000 boepd (95% oil) from a broad portfolio of 12 fields, with no individual field accounting for over 25% of forecast production.

The Company has made good operational progress in Q1-2015 and a number of this year's key activities have already been completed. Water injection on the Causeway field has commenced following completion of the work required on the Taqa-operated North Cormorant platform facilities. The electrical submersible pump on the Fionn field is in service and production from the Pierce field is ramping up following completion of the floating production, storage and offloading ("FPSO") vessel modification works required for tie-in of the third party Brynhild field. Good progress continues to be made on the Wytch Farm well workover campaign, which is scheduled to continue over the course of the year. Completion operations on the Ythan development well are advancing and start-up of production from the field is anticipated in Q2-2015. The Ythan field is being developed as a tie-back to the existing Dons Area infrastructure, in which Ithaca has a corresponding 40% working interest. Approval for development of the field, which will benefit from the Small Field tax Allowance, was granted by the DECC in the third quarter of 2014 following the award of the licence earlier that year.

Ahead of closing out the final allocation data for the month of March, total production in Q1-2015 is estimated to be over 12,500 boepd, 95% oil. This is in line with the forecast performance for the quarter that is reflected in the annual production guidance of 12,000 boepd.

Production in the second quarter of the year is expected to be broadly in line with the first quarter. In Q2-2015 production from the Ythan field is scheduled to commence, although some reduction in overall volumes during the period is anticipated as a result of the commencement of a planned maintenance shutdown of the Sullom Voe Terminal curtailing exports from the Dons and Causeway Area towards the end of the quarter.

RESPONDING TO LOWER OIL PRICE ENVIRONMENT

As part of managing and minimising the impact of the abrupt decline in oil prices since the middle of 2014, the Company has taken a number of important steps to protect the business from a prolonged period of weak oil prices. In addition to the extended cashflow protection provided by additional oil hedging executed since the start of the year and the modest 2015 production enhancements capital expenditure programme, the Company and its partners continue to actively work on delivering supply chain cost efficiencies and reductions, removing overheads and resetting the cost base to reflect the requirements of the current environment. For example the Company has notably actioned a significant reduction in the Athena cost base.

Under the terms of the amended contract for the BW Athena FPSO, the Athena co-venturers will make advanced payment of an FPSO demobilisation fee and from the end of the primary contract term in June 2015, the vessel day rate will no longer apply and the co-venturers and BW Offshore will instead share the net cashflow generated from the field. The revised vessel lease is terminable on 60 days notice. Execution of the revised FPSO contract is clearly a positive step for extending the life of the Athena field and is reflective of the pragmatic approach being taken by many North Sea suppliers to realign cost structures to the current low oil price environment. The Athena field accounts for less than 8% of Ithaca's forecast 2015 production and no year-end reserves have been assigned to the field interest.

COMMODITY HEDGING

Successful hedging strategy used to maximise cashflows and provide significant downside price protection

As part of its overall risk management strategy, the Company's commodity hedging policy is centred on underpinning revenues from existing producing assets at the time of major capital expenditure programmes and locking in asset acquisition paybacks. Any hedging is executed at the discretion of the Company as there are no minimum requirements stipulated in any of the Company's debt finance facilities.

At the start of 2015 the Company had in place oil price hedges of approximately 3.4 million barrels or 6,300 barrels of oil per day ("bopd") for the period from 1 January 2015 to 30 June 2016 at an average price of $102/bbl. In Q1-2015 the Company increased its oil hedging protection to:

· 8,300 bopd hedged at $91/bbl from January 2015 to June 2016

· 4,000 bopd hedged at $69/bbl from July 2016 to June 2017

In addition the Company accelerated the receipt of the cash benefits of a portion of the accumulated hedging gains, increasing the realised gain in Q1-2015 by $60 million to approximately $80 million at an annualized cost of under 2.5% p.a.

Ithaca's updated oil hedge position post Q1-2015 after taking account of the price impact of the value acceleration is summarised as follows:

· 9,000 bopd hedged at $76/bbl from April 2015 to June 2016

· 4,000 bopd hedged at $69/bbl from July 2016 to June 2017

Additionally, for gas years 2015-16 the Company has put options establishing a gas price floor of £0.58/therm (~$10/MMbtu) for 190 million therms (~20 billion cubic feet) of production from the Stella field. Given the gas hedging is in the form of put options, the financial benefit of the hedges will be realised regardless of production in the relevant period.

GREATER STELLA AREA DEVELOPMENT

Substantial progress made on execution of GSA development in 2014 - production start-up now scheduled for Q2-2016 due to delays on FPF-1 modifications programme

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 Ithaca operated 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, the hub will start-up with five Stella wells. Further wells will then be drilled post first hydrocarbons from Stella to maintain the gas processing facilities on plateau.

Installation of the GSA central infrastructure and development of the Stella field are at an advanced stage of completion. Significant progress has been made on the FPF-1 modifications programme, the critical path item for delivering first hydrocarbons from the GSA hub, although there have been disappointing delays to the schedule as a result of the modifications work progressing more slowly than planned. As announced in February 2015, sail-away of the FPF-1 floating production facility from the Remontowa yard in Poland to the field is anticipated late in the first quarter of 2016, resulting in first hydrocarbons in the second quarter of that year.

Stella development drilling programme nearing completion - clean-up flow test on final well expected in April 2015

Drilling Programme

The first four of the five planned Stella development wells have been completed, with operations on the fifth well on-going. Clean-up flow tests have been performed via the drilling rig on each of the four wells to ensure an efficient start-up of the field once the FPF-1 is on location and also to obtain additional reservoir data and hydrocarbon fluid samples. The testing programme involves flowing the wells at various rates, typically over a few days, and performing a maximum flow test. The maximum flow tests have yielded rates of over 10,000 boepd from each of the wells, resulting in a combined maximum rate in excess of 45,000 boepd (100%). This production capacity significantly de-risks the initial annualised production forecast for the GSA of approximately 30,000 boepd (100%), 16,000 boepd net to Ithaca.

The fifth well has been drilled in the Stella Ekofisk chalk reservoir, which underlies the main Stella Andrew sandstone reservoir in which the first four wells have been located. A 2,137 foot gross horizontal reservoir section has been drilled and completed, with the well intersecting a net reservoir interval of 2,073 feet (97% net pay) and extensive natural fractures along the entire length. The planned chemical stimulation programme on the reservoir section has been completed. This is designed to enhance the natural fracture network of the reservoir. The clean-up flow test that will be performed on the well is expected to commence in early April 2015, following the completion of which the ENSCO 100 rig will be demobilised. This will mark the end of the drilling component of the overall Stella development programme.

Subsea infrastructure installation programme scheduled for completion in summer 2015

Subsea Infrastructure WORKS

Solid progress was made in 2014 with execution of the various subsea infrastructure installation activities and the overall subsea programme is now over 80% complete.

Technip is scheduled to recommence offshore operations in April 2015 in order to complete the remaining infrastructure installation activities prior to the arrival of the FPF-1 on location: installation of the Single Anchor Loading ("SAL") structures that will be used for exporting oil from the FPF-1 to shuttle tankers, the mid-water arch over which the risers and umbilicals connecting the subsea infrastructure to the FPF-1 will be positioned, tie-in of two wells at the northern drill centre / one well at the main drill centre and the installation and tie-in of the 3 kilometre oil export pipeline from the FPF-1 riser base to the SAL structures. These activities are scheduled for completion in the third quarter of the year.

The final element of the overall subsea works, which will be completed as part of the FPF-1 hook-up activities when the vessel arrives on location, will be the installation of the dynamic risers and umbilicals.

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

Slower than envisaged progress with the FPF-1 modification works has delayed the forecast sail-away schedule - incentivised mechanical completion schedule now agreed between Petrofac and Remontowa to underpin close out of construction phase

FPF-1 Modification Works

The key focus of the remaining FPF-1 modification works being completed by Petrofac is close out of the construction programme and completion of the vessel commissioning activities required to enable sail-away of the FPF-1 from the Remontowa yard in Poland. The FPF-1 is in an advanced state of mechanical completion. Over three quarters of the construction works have been finished and mechanical completion is scheduled for the third quarter of 2015. The vessel commissioning programme is planned to commence in parallel with completion of construction activities in the middle of the year and is forecast to take approximately six months.

Manning and activity levels remain high in the yard, with Petrofac having agreed an incentivised schedule with the Remontowa yard for the delivery of mechanical completion. All the main equipment has been positioned on the vessel, over 85% of the pipework installed and more than 50% of the electrical and instrumentation cabling installed. The main outstanding construction activities are completion of pipework pressure testing, electrical and instrumentation cable glanding and termination and instrumentation device installation. Pre-commissioning activities have commenced, along with the preparation of operational procedures for conducting the offshore commissioning and start-up phase of the development.

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.

PORTFOLIO MANAGEMENT

SW HEATHER

In December 2014 the Company obtained an additional 47% interest in Licence P.242 (Block 2/5), increasing its working interest to 55% (MOL 45% working interest), and took over operatorship from EnQuest. The licence contains the SW Heather Brent oil reservoir discovery and lies adjacent to the producing Broom field in which Ithaca has an 8% working interest.

UK PORTFOLIO RESTRUCTURING

As part of maximising the overall value of the Company's production portfolio and managing the shift to a substantially lower Brent price outlook, measures are being undertaken to high grade the portfolio and remove high cost, marginal assets. During the first quarter of 2015 the planned re-transfer of the Beatrice facilities to Talisman was completed. As previously announced, the Company is also planning for cessation of production from the Anglia field at the end of 2015 as a result of the netbacks for the field coming under increased pressure from escalating infrastructure costs in the UK Southern Gas Basin.

The carrying value of Beatrice, Anglia and Athena assets has been written down to nil in the accounts and provisions made for any onerous contracts remaining until cessation from the fields.

UK LICENCE MANAGEMENT ACTIVITIES

Other licence management activities during 2014 have been focused on the following:

· 28th UK Licence Round. The Company was awarded three licences: Block 29/10d (Ithaca 54.66% working interest and operator, Dyas 25.34%, Petrofac 20%) in the vicinity of the Company's existing GSA interests; Block 211/13c (part) and 211/18c (part) in the vicinity of the Company's existing Dons Area licences (Ithaca 20% working interest, EnQuest 60% and operator); and, Block 22/15a and 23/11d containing the Banks and Esperanza light oil discoveries (Ithaca 100% working interest and operator), which are located close to nearby producing fields such as Everest and Huntingdon. The licence awards are based on the completion of technical studies.

· Relinquishment of Licence P.1994 (Block 15/17b), containing the "Piper Isles" discoveries. The licence terms required a commitment to be made to either drilling a well on the block or relinquishing it. Such a well commitment was not deemed appropriate at this time by the licence co-venturers, Ithaca and Premier Oil.

DRILLING ACTIVITY

· Norway: During 2014 the Company completed its restructuring of the Norwegian portfolio transferred as part of the Valiant acquisition and participated in two wells in the North Sea area of the Norwegian Continental Shelf. The Trell oil discovery was made on licence PL102 F/G, while the Lupus well on licence PL507 failed to encounter hydrocarbons. In 2015 the Company will participate in two wells: the Talisman Norge operated Snømus well in PL672, which is scheduled to be drilled in Q2-2015, and the Premier Oil Norge operated Myrhauk well in PL539 in Q3-2015. Both wells are located in the Norwegian North Sea and are targeting oil close to existing infrastructure.

· Handcross (UK): Following completion of the highly 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 commitment well transferred as part of the Valiant acquisition was drilled on the prospect in early 2014. No hydrocarbons were encountered by the well in the target formation.

RESERVES

Strong 2014 2P reserves growth driven by the addition of the Summit Assets

Solid 2P reserves valuation performance achieved in 2014 - the impact of lower future oil and gas price assumptions and the realised value of production during the year were more than offset by growth in the portfolio

· 2P reserves at 31 December 2014 were 70.5 MMboe (54% oil), as independently assessed by Sproule. This represents a 22% increase on the previous year, driven primarily by the addition of the Summit Assets and the positive impact of portfolio changes outweighing the reduction attributable to 2014 production and the negative revisions associated with the impact of lower future oil and gas price assumptions.

· The Company's 2P reserves have increased at a compound annual growth rate of approximately 12% since the end of 2011.

· The Company has a balanced producing and development asset reserve base, with approximately 26.6 MMboe or 38% of total 2P reserves associated with producing assets. This represents a year on year increase of approximately 16%.

· The 2P reserves post-tax net asset value discounted at 10% ("NPV-10") assessed by Sproule as at 31 December 2014 was $1,744 million, 5% higher than the previous year as the addition of the Summit Assets and portfolio changes more than offset the value realised in 2014 from production and the impact of lower future oil and gas price assumptions.

· Total proved ("1P") reserves comprise 31.2MMboe or 44% of the Company's 2P reserves base, accounting for approximately 48% of the total 2P NPV-10.

· The 2014 2P reserves replacement ratio was approximately 400%.

· The movement in total 2P reserves between end-2013 and end-2014 is summarised in the following table. The production during 2014 reflects the inclusion of the Summit Assets from the acquisition completion date of 31 July 2014.

SELECTED ANNUAL INFORMATION

· Revenues have reduced by approximately 9% in 2014 mainly as a result of a decrease in the realised oil price. The increase in revenues from 2012 to 2013 was due primarily to the acquisitions of the Valiant assets and an additional interest in the Cook field in the first half of 2013.

· In 2014 a non-cash impairment charge of $173 million (post-tax) turned a pre impairment post-tax profit of $148 million into a post-tax loss of $25 million. The impairment resulted from materially lower near term oil prices assumptions.

· Total assets increased from 2013 to 2014 mainly as a result of the acquisition of the Summit Assets and significant capital investment on the GSA development and production enhancement activities, partially offset by impairment write downs driven by the oil price environment. The movement from 2012 to 2013 was due primarily to the Valiant acquisition combined with GSA development investment.

(1) Refer explanatory footnote per page 1

(2) Weighted average number of shares

2014 RESULTS OF OPERATIONS

REVENUE

Strong underlying revenue of $378.6 million before hedging gains

Revenue decreased by $35.3 million in 2014 to $378.6 million (2013: $413.9 million). This was mainly driven by a decrease of $10/bbl or 9% in the realised oil price, partly offset by a 39kboe increase in underlying sales volumes.

Oil sales volumes increased in 2014 primarily due to the inclusion of production from the Summit Assets from July 2014, coupled with a full year of production from the Dons and Causeway Area. This increase was partially offset by lower volumes from the Athena, Beatrice and Jacky fields as a result of natural rates of production decline from the fields.

The decrease in gas sales in 2014 compared to 2013 was due to a lower realised price together with reduced volumes from Anglia and Topaz, partly offset by increased volumes from the Cook field due to the increased working interest resulting from the Summit acquisition.

There was a decrease in average realised oil prices from $107/bbl in 2013 to $97/bbl in 2014. The average 2014 Brent price was $99/bbl compared to $109 for 2013. 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 and under contracts with differing timescales for pricing. This decrease in realised oil price was nonetheless partially offset by a realised hedging gain of $3/bbl in the year.

COST OF SALES

Cost of sales increased in 2014 to $403.9 million (2013: $327.0 million) driven by increases in operating costs and depletion, depreciation and amortization ("DD&A").

Underlying operating costs increased in the year to $208.8 million (2013: $149.8 million) primarily due to the inclusion of a full year of costs for the Dons and Causeway fields acquired from Valiant and the addition of the Summit Assets acquired in the second half of 2014, coupled with higher cost share contributions for the use of third party infrastructure, particularly the Sullom Voe Terminal ("SVT") that processes oil from the Company's Northern North Sea assets.

2014 operating costs include $12 million associated with a SVT 2013 reconciliation charge that the Company was notified of in 2014. Following a full audit visit, this non-recurring item was recognised as a cost and was settled in Q3 2014. As previously advised, agreements are in place to simplify the method of allocation of SVT costs after 2014 and to base the allocation predominately on oil throughputs, making forecasting more straightforward and reducing the potential significant cost allocation distortions inherent in the current allocation process.

Excluding the impact of the non-recurring SVT prior year charges, 2014 underlying unit operating costs were $52/boe. Bringing in other income (Nigg cost contribution) and offsetting forex gains, adjusted unit operating costs were $49/boe for the full year.

With the cessation of the high operating cost Beatrice and Jacky fields in Q1 2015 and the full impact of production from the low cost Summit Assets, including recommencement of production from the Pierce field, unit operating costs in 2015 are forecast to reduce to under $40/boe. In addition, however, further cost reductions are now anticipated as a result of the deflationary effect of lower oil prices on supply chain costs.

DD&A expense for the year increased to $167.4 million (2013: $158.3 million), including $66.5 million related to business combination uplift DD&A (2013: $60.6 million). This was primarily due to slightly higher year on year production combined with a different contributing field mix, for example, the inclusion of the Summit Assets and the exclusion of Beatrice and Jacky (previously written down to nil in anticipation of their re-transfer to Talisman). This resulted in the unit DD&A rate for the year remaining unchanged at $42/boe (2013: $42/boe).

An oil and gas inventory movement of $14.6 million was charged to cost of sales in 2014 (2013 charge of $17.9 million). This comprised a $1.7 million credit as a result of increased stocks arising from the timing of liftings, coupled with a $16.3 million charge to cost of sales on the revaluation of stock driven by the reduction in oil price from $110/bbl at the beginning of the year compared to $55/bbl at December 31, 2014.

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 2014 marginally fewer barrels of oil were sold (3,788kbbl) than produced (3,789kbbl), mainly as a result of the timing of Cook, Causeway and Dons field liftings.

* Acquired as part of the Summit acquisition

IMPAIRMENT CHARGES AND EXPLORATION & EVALUATION EXPENSES

Non-cash 2014 impairment driven by lower near term oil and gas price assumptions

Exploration and evaluation expenses of $7.1 million were recorded in the year (2013: $18.7 million) primarily due to the decision not to pursue various exploration opportunities in Norway ($4.5 million). It should be noted that approximately 78% of any Norwegian expenditure of this nature is recoverable as a cash tax refund from the Norwegian government. The remainder ($2.6 million) relates to other UKCS E&E prospects, which were deemed uncommercial and therefore the related expenditure was expensed.

Impairment charges of $441.5 million on Development and Production ("D&P") assets, including onerous contract provisions of $21.6 million, were recorded in the year (2013: $52.9 million) driven primarily by the lower commodity price environment leading to a decrease in the asset valuation. The impairment review was carried out on a fair value less cost of disposal basis, using risk-adjusted cash flow projections discounted at a post-tax discount rate of 9%. For details of the assumptions used, refer to the 2014 annual financial statements.

The Company provides for future losses on long-term contracts where it is considered that the contract costs are likely to exceed revenues in future periods. Onerous contract provisions totalling $21.6 million have therefore been made for the fully written down Beatrice, Jacky and Nigg assets subsequent to their write off in December 2013 as well as Anglia and Athena, both of which have been fully written down in 2014 due to the expectation that 2015 may be the last year of production given costs may well exceed revenues in the current price environment.

The impairment charge in 2013 was as a result of the planned re-transfer of the Beatrice facilities to Talisman in Q1-2015, and the associated cessation of production from the Beatrice and Jacky oil fields.

ADMINISTRATION EXPENSES

G&A expenditure forecast to fall in 2015 due to on-going cost reduction measures

Total administrative expenses increased in the year to $13.9 million (2013: $10.7 million) primarily due to an increase in general and administrative expenses as a result of the continued growth of the Company. Around $6 million of the General and Administration ("G&A") cost relates to the costs of the Norwegian office, however, approximately $3.5 million is recovered as a cash tax refund from the Norwegian government - the credit is recorded under Taxation. Share based payment expenses increased as a result of more options being granted in 2014 (2013 annual award not granted until January 2014 with 2014 annual award being granted in December 2014), therefore higher amortisation expense throughout 2014.

G&A costs are anticipated to reduce in 2015 as a result of various cost reduction actions that have been implemented in response to the lower oil price environment.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

Significant strengthening in the US$ over H2-2014 - benefitting predominantly sterling denominated operating expenditure

A foreign exchange gain of $8.4 million was recorded in 2014 (2013: $1.0 million gain). The majority of the Company's revenue is US dollar driven while expenditures are incurred predominantly in British pounds, although US dollar and Euro denominated costs are also incurred. General volatility in the USD:GBP exchange rate is the primary driver behind the foreign exchange gains and losses (GBP:USD at January 1, 2014: 1.65. GBP:USD at December 31, 2014: 1.55 with fluctuation between 1.55 and 1.72 during the year).

The Company recorded an overall $175.2 million gain on financial instruments for the year ended December 31, 2014 (2013: 21.7 million loss). A $14.0 million gain was realised in respect of instruments which expired during the year - $10.3 million realised gain on commodity hedges and a $4.0 million realised gain on foreign exchange instruments, with a small realised loss on interest rate swaps of $0.3 million. Also contributing significantly to the gain was the revaluation of instruments at December 31, 2014, which relates to instruments still held at year end. This $161.2 million revaluation primarily related to a gain on revaluation of commodity hedges due to an increase 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 at $55 on December 31, 2014 (compared to $110 at December 31, 2013) resulting in a mark-to-market gain on commodity hedges that were entered into to provide downside revenue protection and underpin capital expenditure programmes and the Summit acquisition.

FINANCE COSTS

Finance costs increased to $32.1 million in 2014 (2013: $19.4 million). This rise primarily reflects increased interest and fees incurred in relation to additional drawings under the Company's RBL debt facility combined with interest on the senior notes (completed Q3 2014). Debt drawn in the period has increased from $444 million in 2013 to $798 million in 2014 following continued investment in the GSA development programme and the acquisition of the Summit Assets.

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, resulting in total 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. The majority of this liability was utilised or released during 2013 and 2014. 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 prior to 2020

A tax credit of $307.9 million was recognized in the year ended December 31, 2014 (2013: $104.5 million). $310.8 million is a non-cash credit relating to UK taxation and is a product of adjustments to the tax charge primarily relating to the UK Ring Fence Expenditure Supplement, recognition of Small Field Allowance for the Ythan development and additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac (refer to note 28 in the 2014 Consolidated Financial Statements).

A credit of $1.8 million relates to Norway, with $27.4 million of a current tax credit due to Norwegian tax refunds generated by exploration expenditure incurred by Ithaca's Norwegian operations during 2014. This is offset by deferred tax movements of $25.7 million relating to the increased NBV of the Norwegian exploration assets. Further Norwegian tax refunds totalling $32.4 million relate to Norwegian capital expenditure and are recognised on the balance sheet.

The offsetting charge of $4.7 million in 2014 relates to Petroleum Revenue Tax ("PRT") of 50% payable on cashflows generated by the Company's Wytch Farm field interest. In the March 2015 budget, the UK government announced that the rate of PRT would reduce to 35% effective from 1 January 2016.

As a result of the above factors, the loss after tax decreased to $24.5 million (2013: $144.7 million profit).

No Corporation or Supplementary tax is expected to be payable prior to 2020 relating to UK upstream oil and gas activities as a result of the $1,496 million of UK tax allowances available to the Company.

The UK government announced in its March 2015 budget that the effective rate of corporate income tax on oil and gas companies will be reduced from 62% to 50% with effect from 1 January 2015. This does not impact the anticipated timeframe in which the Company will become tax paying.

2014 CAPITAL EXPENDITURE

Continued significant investment in GSA development in 2014

$246.2 million of the total $596.4 million capital additions to development and production ("D&P") assets in 2014 was attributable to the fair value on acquisition of the Summit Assets resulting from business combination accounting (the total net acquisition cost being $163 million). $8.4 million reflects non-cash reductions in decommissioning liabilities relating to various revised cost estimates, discount rates and changes to the expected timing of the expenditure. The remaining D&P additions of $358.6 million relate primarily to capital expenditures on the GSA development and various production enhancement activities completed during the year (as described above).

Capital additions to E&E assets in 2014 were $48.1 million, offset by a $7.4 million release of the acquired E&E liability, as well as a $1.4 million transfer from E&E to D&P assets relating to the Ythan field development following approval of the Field Development Plan in Q3-2014, resulting in a net addition of $39.3 million. Expenditure was primarily focused on the Trell and Lupus exploration wells in Norway where 78% of the cost is subsequently reimbursed by the Norwegian government, resulting in an E&E expenditure (excluding any provision releases) net of Norwegian tax refund of $14.1 million.

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

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

As at December 31, 2014, Ithaca had a net working capital balance of $72.2 million including an unrestricted cash balance of $19.4 million. Available cash has been, and is currently, invested in money market deposit accounts with BNP Paribas. Management has received confirmation from the financial institution that these funds are available on demand.

Cash and cash equivalents decreased as a result of on-going investments on the GSA development and various production enhancement activities. 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, 2014 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, 2014, Ithaca had two UK bank debt facilities available, being the $610 million RBL Facility and the $100 million corporate debt facility. The Company also had $300 million senior unsecured notes, which were issued in July 2014. At year end, the Company had unused UK bank debt facilities totalling approximately $229.4 million (Q4 2013: $300 million), with approximately $480.6 million drawn under the RBL facility.

Additionally at December 31, 2014, the Company had a Norwegian tax refund facility (the "Norwegian Facility") of NOK 600 million (~$80 million). Any drawings under this facility are fully offset by a tax refund receivable from the Norwegian government within a maximum of 24 months. Following the tax receivable paid in December 2014, approximately $17.4 million was drawn on the facility as at December 31, 2014.

During the year ended December 31, 2014 there was a cash outflow from operating, investing and financing activities of approximately $44 million (2013 inflow of $32 million).

Cashflow from operations

Cash generated from operating activities was $150 million primarily due to cash generated from Cook, Dons, Athena, Causeway, Wytch Farm and Broom operations.

Cashflow from financing activities

Cash generated from financing activities was $344 million primarily due to issuance of the $300 million senior notes in July 2014 together with drawdowns of the existing debt facilities in 2014.

Cashflow from investing activities

Cash used in investing activities was $595 million. $163 million of this related to the cash consideration paid on the Summit acquisition. The remainder was primarily further capital expenditure on the GSA development, relating to drilling, FPF-1 modification works and subsea infrastructure construction and installation activities.

The Company is in the process of extending its RBL facility to a standard tenor that will better synchronise its duration with the revised Stella start-up schedule. The extension is expected to be closed out along with the scheduled semi-annual borrowing base review in Q2-2015 and has strong support from the Company's banking syndicate.

The existing bank facilities are forecast to be sized sufficiently to ensure that sufficient financial resources are available to cover anticipated future commitments when combined with existing cash balances and forecast cash from operations. No unusual trends or fluctuations are expected outside the ordinary course of business.

The Company was in compliance with all its relevant financial and operating covenants during the year. The key covenants on the RBL facility are forward looking in nature calculated using bank defined parameters and assumptions. The three key covenants are:

· A corporate cashflow projection showing total sources of funds exceed total forecast uses of funds for the following 12 months.

· The ratio of the net present value of cashflows secured under the RBL for the economic life of the fields to the amount drawn under the facility not falling below 1.15:1.

· The ratio of the net present value of cashflows secured under the RBL for the life of the debt facility to the amount drawn under the facility not falling below 1.05:1.

There are no financial maintenance covenant tests under the senior notes.

The principal covenants under the undrawn Corporate Facility are:

· The ratio of total debt to earnings before interest, tax, DD&A, impairment, exceptional or extraordinary expenditure and E&E write-offs ("EBITDAX"), calculated quarterly on a trailing 12-month basis as of the last day of each quarter, must not exceed 3.0:1 or 3.5:1 if any one of the two previously tested ratios have been at or below 3.0:1.

· The ratio of EBITDAX to total debt costs, calculated quarterly on a trailing 12-month basis as of the last day of each quarter, must not be less than 4.0:1.

Note no funds have or are forecast to be drawn under the Corporate facility.

The key covenant in the Norwegian Tax Refund Facility is the quarterly provision of a cashflow forecast showing that the Norwegian subsidiaries have available funds to execute planned activities for the year to December in each calendar year.

2015 CAPITAL INVESTMENTS

The Company anticipates net 2015 capital expenditure to total approximately $150 million, a near 60% reduction compared to the previous year. Approximately two-thirds of the expenditure relates to the GSA, with the balance associated with completion and tie-in of the on-going Ythan development well, continuation of the Wytch Farm well workover programme, asset maintenance activities and two Norwegian wells (net of the 78% Norwegian tax refund).

The committed capital expenditure in 2016 is currently anticipated to be around $50 million of which half relates to completion of Stella start-up works.

Given the schedule of activities for 2015, capital expenditure is expected to be weighted towards the first half of the year. The programme is forecast to be fully funded on an annual basis by operating cashflows generated from the Company's currently producing asset portfolio, based on current Brent oil prices and reflecting the benefit of the oil price hedges that have been executed and anticipated operating costs for the year.

COMMITMENTS

The Company's commitments relate primarily to capital expenditure on the GSA development, in addition to more limited commitments associated with completion of drilling activities on the Ythan field and the Wytch Farm well workover programme. Rig commitments reflect rig hire costs relating to the fifth Stella well and the Ythan well. Operating commitments related to the lease of the BW Athena FPSO have been included within the onerous contracts provision at 31 December 2014.

As noted above, these commitments are expected to be funded through the Company's existing cash balance, forecast cashflow from operations and available debt facilities.

FINANCIAL INSTRUMENTS

All financial instruments are initially measured in the balance sheet at fair value. Subsequent measurement of the financial instruments is based on their classification. The Company has classified each financial instrument into one of these categories:

The classification of all financial instruments is the same at inception and at December 31, 2014.

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

COMMODITIES

The following table summarises the commodity hedges in place at the end of the year.

As noted above within the Commodity Hedging section, in Q1-2015 the Company increased its oil hedging protection by 2.6 million bbls to 8,300 bopd hedged at $91/bbl from January 2015 to June 2016 and 4,000 bopd hedged at $69/bbl from July 2016 to June 2017.

In addition the Company accelerated the receipt of the cash benefits of a portion of the accumulated hedging gains. Ithaca's updated oil hedge position after taking account of the price impact of the value acceleration is 6,600 bopd hedged at $76/bbl from January 2015 to June 2017.

In Q1-2015 the Company also entered into further gas swaps of 13 million therms of production at £0.47 for the period to Q1 2017.

FOREIGN EXCHANGE

The table below summarises the foreign exchange financial instruments in place at the end of the year.

Post year end the Company entered into £67 million of FX forwards at an average GBPUSD forward rate of 1.48 for the period to December 2016.

INTEREST RATES

The Company also enters into interest rate swaps as a measure of hedging its exposure to interest rate risks on the loan facilities. As at the end of the year, the Company has hedged interest payments on the following:

Q4-2014 FINANCIAL RESULTS

Sales revenue decreased from $111.7 million in Q4 2013 to $88.8 million in Q4 2014. The decrease was predominantly due to an 11% increase in oil sales volumes being more than offset by a 29% fall in average realised oil prices ($76/bbl in Q4 2014 compared to $108/bbl in Q4 2013). Gas volumes were up 37% on the same period in 2013, however, this was offset by lower realised prices ($28/boe in Q4 2014 compared to $38/boe in Q4 2013).

Cost of sales increased to $126.3 million in Q4 2014 (Q4 2013: $91.1 million). The main drivers behind the increase were increased operating costs coupled with a significant movement in inventory.

Operating costs increased primarily due to the additional of the Summit Assets that were acquired in Q3-2014, coupled with higher costs per boe on certain fields, namely Beatrice, Jacky, Athena and Anglia.

Movement in inventory was a charge of $21.7 million in Q4 2014 compared to a charge of $3.1 million in Q4 2013. As noted above, 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 Q4 2014 more barrels of oil were sold (1,127kbbl) than produced (1,023kbbl), mainly as a result of the timing of Cook, Causeway, Dons and Wytch Farm field liftings.

DD&A stayed broadly equivalent at $45.8 million in Q4 2014 compared to $46.4 million in Q4 2013. This small decrease was primarily due to field mix, including the addition of Summit Assets offset by Beatrice and Jacky no longer forming part of the charge given they were fully written off at the end of 2013. The blended rate for the quarter decreased from $44/boe in Q4 2013 to $42/boe in 2014 primarily due to this field mix.

QUARTERLY RESULTS SUMMARY

1 Q2-13 and Q3-13 restated to account for adjustment to Valiant acquisition accounting

2 Based on weighted average number of shares

The most significant factors to have affected the Company's results during the above quarters, other than transactions such as the Valiant and Summit Asset acquisitions, 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. In addition, the significant reduction in underlying commodity prices has resulted in impairment write downs in Q4 2014 as noted above.

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, 2014 Ithaca had 329,518,620 common shares outstanding along with 24,232,428 options outstanding to employees and directors to acquire common shares.

In 2014, the Company's Board of Directors granted 15,905,000 options at a weighted average exercise price of C$1.81. 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.

(1) Represents the TSX close price (CAD$1.19) on December 31, 2014. US$:CAD$ 0.85993 on December 31, 2014.

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, listed below, and its associates FPU Services Limited ("FPU") and FPF‐1 Limited ("FPF‐1").

Wholly owned subsidiaries:

 Ithaca Energy (Holdings) Limited ("Ithaca Holdings"),

 Ithaca Energy (UK) Limited ("Ithaca UK"),

 Ithaca Minerals North Sea Limited ("Ithaca Minerals")

 Ithaca Energy Holdings (UK) Limited ("Ithaca Holdings UK")

 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 North Sea Limited (formerly Valiant North Sea 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)

 Ithaca SPL Limited (formerly Summit Petroleum Limited)

 Ithaca SP UK Limited (formerly Summit Petroleum UK Limited)

 Ithaca Dorset Limited (formerly Summit Dorset Limited)

 Ithaca Pipeline Limited (formerly Summit Pipeline Limited)

The consolidated financial statements include, from July 31, 2014 only (being the acquisition date), the consolidated financial statements of the Summit group of companies and from April 19, 2013 only (being the acquisition date), the consolidated financial statements of the Valiant group of companies.

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 of disposal 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 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

The Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of the Company's disclosure controls and procedures as at December 31, 2014, and concluded that such disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual filings, interim filings and other reports filed or submitted under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and such information is accumulated and communicated to the Company's management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosures.

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 for external purposes in accordance with IFRS including those policies and procedures that:

(a) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company's assets;

(b) are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with IFRS, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

(c) are designed to provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the annual financial statements or interim financial statements.

The Chief Executive Officer and Chief Financial Officer performed an assessment of internal control over financial reporting as at December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), and concluded that internal control over financial reporting is effective 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, 2014, there were no changes in the Company's internal control over financial reporting that occurred during the year ended December 31, 2014 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, 2014, 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(R).

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

New and amended standards and interpretations need to be adopted in the first interim financial statements issued after their effective date (or date of early adoption). There are no new IFRSs of IFRICs that are effective for the first time for this interim period that would be expected to have a material impact on the Company.

ADDITIONAL INFORMATION

Non-IFRS Measures

"Cashflow from operations" and "cashflow per share" referred to in this MD&A are not prescribed by IFRS. These non-IFRS financial measures do not have any standardized meanings and therefore are unlikely to be comparable to similar measures presented by other companies. The Company uses these measures 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.

"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.

"EBITDAX" referred to in this MD&A is not 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.

"Net drawn debt" referred to in this MD&A is not prescribed by IFRS. The Company uses net drawn debt as a measure to assess its financial position. Net drawn debt includes amounts outstanding under the Company's debt facilities and senior notes, less cash and cash equivalents. Net drawn debt noted above excludes any amounts outstanding under the Norwegian tax rebate facility.

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. Where appropriate, finance leases are recorded on the balance sheet. As at December 31, 2014, finance lease assets of $32.2 million and related liabilities of $31.9 million are included on the balance sheet.

Related Party Transactions

A director of the Company is a partner of Burstall Winger Zammit LLP who acts as counsel for the Company. The amount of fees paid to Burstall Winger Zammit LLP in 2014 was $0.2 million (2013: $0.3 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, 2014 the Company had a loan receivable from FPF-1 Ltd, an associate of the Company, for $58.3 million (December 31, 2013: 31.6 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 therefrom. Full pressure transient and well test interpretation analyses have not been completed and as such the flow test results contained in this MD&A should be considered preliminary until such analyses have been completed.

RISKS AND UNCERTAINTIES

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

For additional detail regarding the Company's risks and uncertainties, refer to the Company's Annual Information Form dated March 30, 2015, (the "AIF") filed on SEDAR at www.sedar.com.

RISK

MITIGATIONS

Commodity Price Volatility

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

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

Foreign Exchange Risk

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

Given the proportion of development capital expenditure and operating costs incurred in currencies other than the US Dollar, the Company routinely executes hedges to mitigate foreign exchange rate risk on committed expenditure and/or draws debt in GB Sterling to settle Sterling costs which will be repaid from surplus Sterling generated revenues derived from Stella gas sales.

Interest Rate Risk

The Company is exposed to fluctuation in interest rates, particularly in relation to the debt facilities entered into.

In order to mitigate the fluctuations in interest rates, the Company routinely reviews cost exposures as a result of varying rates and assesses the need to lock in interest rates.

Debt Facility Risk

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

The Facilities include covenants which restrict, among other things, the Company's ability to incur additional debt or dispose of assets.

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

The financial tests necessary to draw down upon the Facilities needed were met during the year.

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

Financing Risk

To the extent cashflow from operations and the Facilities' resources are ever deemed not adequate to fund Ithaca's cash requirements, external financing may be required. Lack of timely access to such additional financing, or access on unfavourable terms, could limit Ithaca's ability to make the necessary capital investments to maintain or expand its current business and to make necessary principal payments under the Facilities may be impaired.

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

The Company has established a business plan and routinely monitors its detailed cashflow forecasts and liquidity requirements to ensure it will continue to be fully funded.

The Company believes that there are no circumstances that exist at present which require forced divestments, significant value destroying delays to existing programs or will likely lead to critical defaults relating to the Facilities.

Third Party Credit Risk

The Company is and may in the future be exposed to third party credit risk through its contractual arrangements with its current and future joint venture partners, marketers of its petroleum production and other parties.

The Company extends unsecured credit to these and certain other parties, and therefore, the collection of any receivables may be affected by changes in the economic environment or other conditions affecting such parties.

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

The majority of the Company's oil production is sold, depending on the field, to either BP Oil International Limited or Shell Trading International Ltd. Gas production is sold through contracts with RWE NPower PLC, Hess Energy Gas Power (UK) Ltd, Shell UK Ltd. and Esso Exploration & Production UK Ltd. Each of these parties has historically demonstrated their ability to pay amounts owing to Ithaca. The Company has not experienced any material credit loss in the collection of accounts receivable to date.

Property Risk

The Company's properties will be generally held in the form of licenses, concessions, permits and regulatory consents ("Authorisations"). The Company's activities are dependent upon the grant and maintenance of appropriate Authorisations, which may not be granted; may be made subject to limitations which, if not met, will result in the termination or withdrawal of the Authorisation; or may be otherwise withdrawn. Also, in the majority of its licenses, the Company is a joint interest-holder with other third parties over which it has no control. An Authorisation may be revoked by the relevant regulatory authority if the other interest-holder is no longer deemed to be financially credible. There can be no assurance that any of the obligations required to maintain each Authorisation will be met. Although the Company believes that the Authorisations will be renewed following expiry or granted (as the case may be), there can be no assurance that such authorisations will be renewed or granted or as to the terms of such renewals or grants. The termination or expiration of the Company's Authorisations may have a material adverse effect on the Company's results of operations and business.

The Company has routine ongoing communications with the UK oil and gas regulatory body, the Department of Energy and Climate Change ("DECC") as well as Norwegian authorities. Regular communication allows all parties to an Authorisation to be fully informed as to the status of any Authorisation and ensures the Company remains updated regarding fulfilment of any applicable requirements.

Operational Risk

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

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

The Company acts at all times as a reasonable and prudent operator and has non-operated interests in assets where the designated operator is required to act in the same manner. The Company takes out market insurance to mitigate many of these operational, construction and environmental risks.

The Company uses experienced service providers for the completion of work programmes.

The Company uses the services of Sproule International Limited ("Sproule") to independently assess the Company's reserves on an annual basis.

Development Risk

The Company is executing development projects to produce reserves in off shore locations. These projects are long term, capital intensive developments. Development of these hydrocarbon reserves involves an array of complex and lengthy activities. As a consequence, these projects, among other things, are exposed to the volatility of oil and gas prices and costs. In addition, projects executed with partners and co-venturers reduce the ability of the Company to fully mitigate all risks associated with these development activities. Delays in the achievement of production start-up may adversely affect timing of cash flow and the achievement of short-term targets of production growth.

The Company places emphasis on ensuring it attracts and engages with high quality suppliers, subcontractors and partners to enable it to achieve successful project execution. The Company seeks to obtain optimal contractual agreements, including using turnkey and lump sum incentivised contracts where appropriate, when undertaking major project developments so as to limit its financial exposure to the risks associated with project execution.

Competition Risk

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

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

Weather Risk

In connection with the Company's offshore operations being conducted in the North Sea, the Company is especially vulnerable to extreme weather conditions. Delays and additional costs which result from extreme weather can result in cost overruns, delays and, ultimately, in certain operations becoming uneconomic.

The Company takes potential delays as a result of adverse weather conditions into consideration in preparing budgets and forecasts and seeks to include an appropriate buffer in its all estimates of costs, which could be adversely affected by weather.

Reputation Risk

In the event a major offshore incident were to occur in respect of a property in which the Company has an interest, the Company's reputation could be severely harmed

The Company's operational activities are conducted in accordance with approved policies, standards and procedures, which are then passed on to the Company's subcontractors. In addition, Ithaca regularly audits its operations to ensure compliance with established policies, standards and procedures.

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, including the acquisition of the Summit Assets;

· 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, including the Summit acquisition;

· 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 30, 2015. The 2014 results have been compared to the results of 2013. This MD&A should be read in conjunction with the Company's audited consolidated financial statements as at December 31, 2014 and 2013 together with the accompanying notes and Annual Information Form ("AIF") for the year ended December 31, 2014. These documents, and additional information regarding Ithaca, 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, 2014 and forming the basis for the Statement of Reserves Data and Other Oil and Gas information of Ithaca dated March 11, 2015 (the "Statement"). The reserves for the Evelyn South West Heather fields 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 Securities Administrators' 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.

To the Shareholders of Ithaca Energy Inc.

We have audited the accompanying consolidated financial statements of Ithaca Inc and its subsidiaries, which comprise the Consolidated Statement of Financial Position at 31 December 2014 and 31 December 2013, the Consolidated Statement of Income, the Consolidated Statement of Changes in Equity and Consolidated 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 2014 and 31 December 2013 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

30 March 2015

2014

2013

Note

US$'000

US$'000

Revenue

5

378,593

413,937

Operating costs

(220,806)

(149,799)

Oil purchases

(1,087)

(1,063)

Movement in oil and gas inventory

(14,640)

(17,890)

Depletion, depreciation and amortisation

(167,378)

(158,279)

Cost of sales

6

(403,911)

(327,031)

Gross (Loss)/Profit

(25,318)

86,906

Exploration and evaluation expenses

12

(7,105)

(18,737)

Impairment of assets and onerous contracts

14

(441,457)

(52,864)

Total Administrative expenses

7

(13,937)

(20,887)

Foreign exchange

8,405

1,070

Gain/(Loss) on financial instruments

30

175,246

(21,708)

Gain on asset disposal

3,030

1,526

Release of exploration obligation

-

28,472

Negative goodwill

-

55,333

Finance costs

8

(32,071)

(19,364)

Finance income

731

408

(Loss)/Profit Before Tax

(332,476)

40,155

Taxation

28

307,941

104,531

(Loss)/Profit After Tax

(24,535)

144,686

Earnings per share (US$ per share)

Basic

Diluted

27

27

(0.07)

(0.07)

0.48

0.47

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

Consolidated Statement of Financial Position

as at 31 December 2014

Note

2014

US$'000

2013

US$'000

ASSETS

Current assets

Cash and cash equivalents

19,381

63,435

Restricted cash

9

-

12,198

Accounts receivable

10

266,747

314,727

Deposits, prepaid expenses and other

1,140

21,150

Inventory

11

27,481

21,632

Derivative financial instruments

31

150,760

5,102

465,509

438,244

Non-current assets

Long-term receivable

33

58,338

31,655

Long-term Norwegian tax receivable

10

7,032

-

Long-term inventory

11

8,126

8,126

Investment in associate

17

18,337

18,337

Exploration and evaluation assets

12

89,844

57,628

Property, plant & equipment

13

1,435,209

1,423,712

Deferred tax assets

28

139,266

-

Goodwill

16

137,114

985

1,893,266

1,540,443

Total assets

2,358,775

1,978,687

LIABILITIES AND EQUITY

Current liabilities

Trade and other payables

19

(392,131)

(472,396)

Exploration obligations

20

(5,431)

(12,859)

Onerous contracts

14

(21,635)

-

(419,197)

(485,255)

Non-current liabilities

Borrowings

18

(784,859)

(432,243)

Decommissioning liabilities

21

(213,105)

(172,047)

Other long term liabilities

22

(92,020)

(6,037)

Deferred tax liabilities

28

 -

(9,909)

Contingent consideration

24

(4,000)

(4,000)

Derivative financial instruments

31

(587)

(15,550)

(1,094,571)

(639,786)

Net Assets

845,007

853,646

Shareholders' Equity

Share capital

25

551,632

535,716

Share based payment reserve

26

19,234

19,254

Retained earnings

25

274,141

298,676

Total Equity

845,007

853,646

The financial statements were approved by the Board of Directors on 30 March 2015 and signed on its behalf by:

"Les Thomas"

Director

 "Jay Zammit"

Director

For the year ended 31 December 2014

Share capital

Share based

payment

reserve

Retained

earnings

Total

Equity

US$'000

US$'000

US$'000

US$'000

Balance, 1 Jan 2013

431,318

20,340

153,990

605,648

Profit for the year

-

-

144,686

144,686

Total comprehensive income

431,318

20,340

298,676

750,334

Shares issued

93,005

-

 -

93,005

Share based payment

-

3,733

 -

3,733

Options exercised

11,393

(4,819)

 -

6,574

Balance, 31 Dec 2013

535,716

19,254

298,676

853,646

Balance, 1 Jan 2014

535,716

19,254

298,676

853,646

Share based payment

-

6,223

-

6,223

Options exercised

15,916

 (6,243)

-

9,673

Loss for the period

-

-

(24,535)

(24,535)

Balance, 31 Dec 2014

551,632

19,234

274,141

845,007

For the year ended 31 December 2014

2014

US$'000

2013

US$'000

CASH PROVIDED BY (USED IN):

Operating activities

(Loss)/Profit Before Tax

(332,476)

40,155

Adjustments for:

Depletion, depreciation and amortisation

13

167,378

158,279

Exploration and evaluation write off

12

7,105

18,737

Impairment

14

441,457

52,864

Share based payment

1,983

561

Loan fee amortisation

8

4,232

2,580

Revaluation of financial instruments

30

(161,201)

34,590

Gain on disposal

(3,030)

-

Gain on exploration release

-

(29,998)

Movement in goodwill

-

(55,333)

Accretion

8

5,724

4,509

Bank interest & charges

22,035

12,138

Valiant acquisition fees

-

5,032

Cashflow from operations

153,207

244,114

Changes in inventory, debtors and creditors relating to operating activities

73,253

(6,971)

Tax paid

(3,137)

-

Net cash from operating activities

223,323

237,143

Investing activities

Acquisition of Valiant net of cash acquired

-

(200,636)

Cash acquired on acquisition of Valiant

-

11,611

Valiant acquisition fees

-

(5,032)

Acquisition of Cook

-

(33,370)

Acquisition of Summit

15

(163,541)

-

Capital expenditure

(406,413)

(355,874)

Loan to associate

(26,864)

(10,104)

Proceeds on disposal

2,190

1,623

Changes in debtors and creditors relating to investing activities

(19,711)

97,288

Net cash used in investing activities

(614,339)

(494,494)

Financing activities

Proceeds from issuance of shares