H1-2015 Financial Results

2015 HALF YEAR HIGHLIGHTS

Strong underlying cashflow generation - underpinned by reduced unit operating expenditure and significant hedging protection

· H1 2015 production of 12,578 barrels of oil equivalent per day ("boepd"), in line with guidance (H1 2014: 10,528 boepd)

· $160.2 million cashflow from ongoing operations(1) in H1 2015 ($60.3 million in Q2 2015), including realised oil price hedging gains (H1 2014: $102 million)

· Adjusted earnings of $55.3 million in H1 2015, excluding a non-cash accounting tax charge of $41.5 million resulting from a reduction in UK tax rates in Q1 2015 (H1 2014: $17 million)

· Cashflow per share $0.43 (H1 2014: $0.31) and adjusted earnings per share $0.17 (H1 2014: $0.05)

Business resilient to lower oil price environment

· Full year 2015 production guidance remains unchanged at 12,000 boepd (95% oil)

· Two years of oil price hedging in place - average of 6,400 barrels of oil per day ("bopd") at $70/bbl until June 2017

· 2015 operating costs reduced to approximately $35/boe, ~29% lower than for 2014, and forecast to fall further to around $25/boe following Stella start-up

· Cashflows sheltered from UK corporation and supplementary tax payments over the medium term by tax allowances pool of over $1.5 billion at 30 June 2015

· Brent breakeven price for the existing producing asset base of under $10/bbl through to Stella start-up with the benefit of hedges

· Modest capital expenditure of approximately $50 million in H2 2015, reflecting highly advanced status of planned investment programmes

Solid liquidity outlook, with reduced peak debt requirement prior to Stella start-up

· Net debt of $787.9 million at 30 June 2015 ($780.7 million at 31 December 2014)

· Total debt funding capacity of $950 million in place, comprising $650 million reserve base lending facilities and $300 million senior unsecured notes

· Forecast net debt requirement prior to Stella start-up reduced to under $800 million from previous guidance of $825-850 million - largely insensitive to Brent given hedging

· Approximately $30 million net cash payment received on 8 July 2015 following divestment of the Company's non-core Norwegian exploration business to MOL plc post retirement of the Norwegian exploration financing facility and working capital adjustments

Primary focus of GSA activities is on advancing the FPF-1 modifications programme to enable vessel sail-away in late Q1-2016

· FPF-1 modifications programme continues to advance towards the planned vessel sail-away from the yard in late Q1-2016 - current focus on closing out the main construction phase activities and transitioning into start-up of commissioning operations

· Stella development drilling programme completed in April 2015. Overall well results have materially de-risked forecast initial annualised production of 30,000 boepd (100%) from the Stella field, 16,000 boepd net to Ithaca

· 2015 subsea infrastructure installation campaign materially complete - the three kilometre oil export pipeline to the Single Anchor Loading structures has recently been installed and the subsea works are set to be concluded in October 2015 with completion of the final pipeline tie-ins

SUMMARY STATEMENT OF INCOME

(1) Average realised price before hedging

(2) Revenue less stock movements

(3) Q2 2015 Cashflow from On-going Operations of $60.3M less $8.6M onerous contract provision release = total cashflow from operations of $51.7M

(4) Based on total cashflow from operations

(5) Earnings per share adjusted to exclude impact of reduced tax rates

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

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 and the exploitation of its existing UK producing asset portfolio.

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 Greater Stella Area development

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

· 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

Sale of the Norwegian exploration business completed - Norwegian financing facility repaid and net initial cash payment of ~$30M received

SALE oF NORWEGIAN BUSINESS

In April 2015 the Company entered into an agreement with a subsidiary of the Hungarian listed company MOL Plc (MOL:BUD) to sell its wholly owned subsidiary, Ithaca Petroleum Norge AS ("Ithaca Norge"), for an initial consideration of US$60 million plus the ability to earn additional bonus payments of up to US$30 million dependent on exploration success from the existing licence portfolio. Following repayment and retirement of the Company's Norwegian exploration financing facility and conventional working capital adjustments, a net cash payment of approximately $30 million was received on 8 July 2015. These funds have been used to offset drawings under the Company's existing UK bank debt facilities.

This transaction concludes the highly successful restructuring and monetisation of the Norwegian operations acquired as part of the acquisition of Valiant Petroleum plc in April 2013. The Norwegian portfolio had no production or reserves associated with the licence interests.

The financial statements reflect the sale of the Norwegian business as of 30 June 2015 with the cash proceeds received in July 2015.

Strong liquidity - total debt funding facilities of $950M in place

BANK DEBT FACILITIES EXTENSION

A semi-annual bank borrowing base review was completed as scheduled in April 2015, with the former corporate facility being replaced by a junior Reserve Based Lending ("RBL") facility and the tenor of the senior RBL being extended to September 2018 in order to align the maturity of the two facilities. These changes were designed to simplify the bank debt structure within the business, ensuring that the funding capacity is reflective of the value of the Company's assets and removing the historic financial covenant tests.

The total bank debt facilities have been sized at $650 million; comprising a $575 million senior RBL and a $75 million junior RBL. The facilities are based on conventional oil and gas industry borrowing base financing terms and are available to fund on-going development activities and general corporate purposes. When combined with the existing $300 million senior unsecured notes due July 2019, the debt facilities provide sufficient funding headroom for the business ahead of first hydrocarbons from the Greater Stella Area ("GSA").

PRODUCTION & OPERATIONS

Solid H1 2015 production performance - full year guidance remains unchanged at 12kboe/d

PRODUCTION

Average production for the first six months of the year ("H1 2015") was 12,578 boepd, 93% oil, in line with forecast production for the period. This represents a 19% increase on the same period in 2014 (H1 2014: 10,528 boepd), driven largely by the inclusion of additional production from the assets acquired from Sumitomo Corporation (the "Summit Assets"), which were added to the portfolio in July 2014.

As previously highlighted, production in the third quarter of the year ("Q3 2015") will be below the average guidance level for the year as a result of planned maintenance shutdown activities on the host facilities serving a number of the Company's fields. The shutdowns associated with the Northern North Sea fields, the Dons and the Causeway Area, were successfully completed in July 2015. The approximately two month planned shutdown of the Cook field for execution of life extension works on the Anasuria floating production and offloading facility that serves the field is on-going and is scheduled to be concluded in late September 2015.

Full year 2015 production guidance remains unchanged at 12,000 boepd (95% oil), taking into account the planned maintenance shutdown activities being completed during the year.

OPERATIONS

The producing asset portfolio performed well over H1 2015, with solid operational uptime achieved across the main fields. Good progress was made over the period on all the main production enhancement activities scheduled for 2015 and the only on-going activity in H2 2015 is continuation of the Wytch Farm well workover campaign.

The tie-in of the Ythan field development well was completed at the end of May 2015 and the well was brought on production for the period prior to the commencement of the planned maintenance shutdown of the Dons facilities and the Sullom Voe Terminal in mid-June 2015. Further production data has been obtained since completion of the SVT shutdown in mid-July 2015 and the initial performance of the well has been encouraging. The options and timing for future potential development wells will be assessed as additional production data is obtained from the field.

As previously reported, the contract for the lease of the BW Athena FPSO was renegotiated in early 2015 in order to materially reduce field operating costs. As a consequence payment of the FPSO day rate ceased in June 2015, with the Athena co-venturers and BW Offshore instead sharing future net cashflow generated from the field. Advanced payment of the FPSO demobilisation fee was made at the same time, being approximately $4.5 million net to Ithaca. The amended vessel lease is terminable on 60 days' notice. Given prevailing oil prices it is anticipated that the field may cease production later in 2015, and such step, along with the previously reported planned cessation of the Anglia gas field in late 2015, are aimed at high grading the portfolio and removing high cost, marginal assets. The total net daily production capacity of the two fields is approximately 1,000 boepd, the anticipated cessation of which has been accounted for in the 2015 production guidance.

GREATER STELLA AREA DEVELOPMENT

Overall GSA development activities are at an advanced stage of completion - production start-up scheduled for Q2 2016

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 in the GSA post first hydrocarbons 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. Close out of the FPF-1 modifications programme, which is being completed by Petrofac in the Remontowa yard in Poland, is the critical path item for delivering first hydrocarbons from the GSA hub. Sail-away of the FPF-1 from Poland to the field is anticipated late in the first quarter of 2016, resulting in first hydrocarbons in the second quarter of that year.

Preparation on-going for commencement of main FPF-1 commissioning phase of activities

FPF-1 Modification Works

The FPF-1 modifications programme continues to advance towards the planned sail-away of the vessel from the yard in late Q1-2016. At this stage in the work programme, the focus is on closing out the main construction phase activities and the start-up of commissioning operations. Pipework pressure testing on the topsides processing and utility systems is well advanced and electrical cable termination activities are nearing conclusion, close out of which will facilitate the commencement of the main commissioning phase. Pre-commissioning activities are on-going. The temporary generators required for commissioning are ready on-site, hot oil flushing of package lube oil pipework has commenced and site acceptance testing of the integrated control and safety system equipment is in progress.

Stella development drilling programme successfully completed in April 2015

Drilling Programme

The five well Stella development drilling programme was successfully completed in April 2015. In total the wells have achieved a combined maximum flow test rate during clean-up operations of over 53,000 boepd (100%). This well capacity significantly de-risks the initial annualised production forecast for the GSA hub of approximately 30,000 boepd (100%), 16,000 boepd net to Ithaca.

Completion of 2015 subsea infrastructure installation operations progressing to plan

Subsea Infrastructure WORKS

The 2015 subsea infrastructure installation campaign is in the process of being concluded as planned. Technip has recently completed installation of the three kilometre oil export pipeline from the FPF-1 riser base to the Single Anchor Loading structures and will return in October 2015 to perform the final pipeline tie-ins. This will then conclude the overall 2015 subsea work programme. Thereafter the only remaining subsea workscope relates to the installation and hook-up of the dynamic risers and umbilicals connecting the infrastructure on the seabed to the FPF-1 once the vessel has been anchored on location.

COMMODITY HEDGING

Significant downside commodity price protection from hedging in place

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.

The Company's oil price hedging position is summarised as follows:

· 8,800 bopd hedged at $70/bbl from July 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.

OPERATING EXPENDITURE

Unit operating costs ~$35/boe in H1 2015, ~29% lower than in 2014

As part of managing and minimising the impact of the abrupt decline in oil prices since the second half 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 cashflow protection from the executed oil price hedging, 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.

When combined with the cessation of operations at the high cost Beatrice and Jacky fields and the retransfer of the Beatrice facilities to Talisman in Q1 2015, the 2015 financial results show a step change in unit operating costs compared to the previous year. Specifically, unit operating costs have reduced by 29% to $35/boe compared to the same period in 2014 (H1 2014: $49/boe). This unit operating expenditure reflects inclusion of the costs associated with the Athena and Anglia fields, which were provided for in Q4 2014 as an onerous contract provision. The provision was made and the book value of the fields 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.

Full year unit operating expenditure is anticipated to average around $35/boe, down from the anticipated level at the start of the year of approximately $40/boe.

With the significant benefit of the oil price hedging in place, the Company has a Brent breakeven price for the existing producing asset base of under $10/bbl until Stella start-up.

CAPITAL EXPENDITURE

~$150M 2015 capital expenditure programme approximately two-thirds complete by end H1 2015

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 Ythan development well, continuation of the Wytch Farm well workover programme and asset maintenance activities. In line with guidance, approximately $100 million of the 2015 capital expenditure programme was incurred in H1 2015. This was driven by completion of drilling operations on Stella and Ythan along with the execution of various GSA subsea infrastructure installation works.

Expenditure on the planned capital expenditure programme for 2016 is currently anticipated to total around $50 million, of which half relates to completion of Stella start-up works. There are a number of production enhancement opportunities with the existing producing asset portfolio that could be added to the planned capital expenditure programme, should the prevailing economics justify inclusion. The sanction of any such expenditures are within the control of the Company.

NET DEBT

Forecast peak net debt reduced to under $800 million

Net debt at 30 June 2015 was $788 million out of total debt funding facilities of $950 million. This was lower than the previously indicated expectation for peak net debt of $825-850 million in the second quarter of the year primarily as a consequence of the slower than forecast unwinding of the working capital position associated with investment activities in H1 2015.

Following the approximately $30 million net cash receipt from the sale of the Norwegian business in early July 2015 and forecast operating cashflows for the remainder of the year, the peak net debt requirement prior to Stella start-up is reduced to under $800 million. Given the level of oil hedges in place, this position is largely insensitive to prevailing Brent prices.

Q2 2015 RESULTS OF OPERATIONS

REVENUE

THREE MONTHS ENDED JUNE 30, 2015

Revenue decreased by $40.7 million in Q2 2015 to $59.2 million (Q2 2014: $99.9 million). This 41% reduction was driven by a decrease of $47/bbl or 43% in the pre-hedging realised oil price, partly offset by a modest increase in underlying sales volumes.

Sales volumes increased in Q2 2015 primarily due to the inclusion of production from the Summit Assets, which were acquired in July 2014. This increase was partially offset by the absence of Beatrice and Jacky sales volumes in Q2 2015 following the re-transfer of the Beatrice facilities to Talisman during the quarter, combined with the exclusion of Athena and Anglia revenues, which were accounted for as part of the onerous contracts provision in 2014. If revenues were however to be adjusted to include Athena and Anglia sales volumes, there would be an increase in Q2 2015 revenue to $66.9 million.

The significant fall in Brent from $110/bbl in Q2 2014 to $62/bbl in Q2 2015 drove a decrease in average realised oil prices from $109/bbl in Q2 2014 to $62/bbl in Q2 2015. This decrease was nonetheless partially offset by a realised hedging gain of $34/bbl in the quarter.

The Company's realised 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.

SIX MONTHS ENDED JUNE 30, 2015

Revenue decreased by $70.1 million in H1 2015 to $129.5 million (H1 2014: $199.6 million). This 35% reduction was driven by a decrease of $49/bbl or 45% in the pre-hedging realised oil price, partly offset by a 30% increase in underlying sales volumes.

Sales volumes increased in H1 2015 primarily due to the inclusion of production from the Summit Assets. As noted above, this was partially offset by the absence of Beatrice and Jacky sales volumes together with the exclusion of Anglia and Athena revenues in H1 2015 accounted for as part of the onerous contract provision.

There was a decrease in average realised oil prices from $109/bbl in H1 2014 to $60/bbl in H1 2015. The average Brent price for the six months ended 30 June 2015 was $58/bbl compared to $107/bbl for H1 2014. As above, the Company's realised oil prices do not strictly follow the Brent price pattern. The decrease in realised oil price was partially offset by a realised hedging gain of $24/bbl in the period (excluding the benefit of the accelerated hedging reset).

COST OF SALES

THREE MONTHS ENDED JUNE 30, 2015

Cost of sales decreased in Q2 2015 to $58.1 million (Q2 2014: $88.0 million) driven by decreases in operating costs, depletion, depreciation and amortisation ("DD&A") and movement in oil and gas inventory.

OPERATING EXPENDITURE

Reported operating costs decreased in the quarter to $29.5 million (Q2 2014: $51.9 million) primarily due to the cessation of operations on the high cost Beatrice and Jacky fields in Q1 2015 and re-transfer of the Beatrice facilities to Talisman, combined with the absence of $13.5 million of Athena and Anglia operating costs provided for under the onerous contract provision in Q4 2014. Additionally, there have also been significant cost savings realised across the portfolio as supply chain contract renegotiations and contractor rate reductions have contributed to a fall in actual and forecast offshore facility and processing terminal costs, notably including the removal of the FPSO day rate on the Ithaca operated Athena field from June 2015.

The unit operating costs for the quarter (inclusive of Athena and Anglia) were $37/boe. This represents a reduction of over 20% compared to the rate of $48/boe in Q2 2014. Taking into account one-off costs incurred in the quarter, most significantly being the planned repair of the Broom water injection pipeline, full year unit operating costs are expected to be in the region of $35/boe.

Absent expenditure associated the Athena and Anglia fields, which are expected to cease production in 2015, the underlying unit operating cost in the quarter was under $30/boe.

DD&A

The unit DD&A rate for the quarter decreased significantly to $27/boe (Q2 2014: $48/boe), resulting in the total DD&A expense for the quarter reducing to $31.7 million (Q2 2014: $51.3 million). This reduction was mainly attributable to a different contributing field mix, for example the inclusion of the Summit Assets and the exclusion of Beatrice and Jacky as well as the absence of Athena and Anglia, both of which have also been fully written down. The blended unit cost has been further reduced by the write downs booked in 2014 as a consequence of the change in oil price environment.

MOVEMENT IN INVENTORY

An oil and gas inventory movement of $3.1 million was credited to cost of sales in Q2 2015 (Q2 2014 credit of $15.6 million). Movements in oil inventory arise due to differences between barrels produced and sold, with production being recorded as a credit to movement in oil inventory through cost of sales until the oil has been sold.

SIX MONTHS ENDED JUNE 30, 2015

Cost of sales decreased in H1 2015 to $133.0 million (H1 2014: $174.0 million) due to decreases in operating costs and DD&A, partially offset by the movement in oil and gas inventory.

OPERATING EXPENDITURE

Operating costs decreased in the period to $57.6 million (H1 2014: $93.2 million) as a result of the previously noted enhancement of the overall production mix, with increased production from lower operating cost fields, together with the effect of the wider cost savings achieved across the portfolio as a consequence of the supply chain cost reduction initiatives and the absence of Athena and Anglia costs provided for under the onerous contract provision.

DD&A

DD&A for the period decreased to $62.3 million (H1 2014: $83.8 million). As noted above, this decrease was primarily due to the different contributing field mix along with the impact of the write downs booked in 2014 as a consequence of the change in oil price environment.

MOVEMENT IN INVENTORY

An oil and gas inventory movement of $13.1 million was charged to cost of sales in H1 2015 (H1 2014: credit of $3.7 million). In H1 2015 fewer barrels of oil were produced (2,106 kbbls) than sold (2,279 kbbls), mainly as a result of the timing of Cook and Pierce field liftings.

IMPAIRMENT CHARGES AND EXPLORATION & EVALUATION EXPENSES

Exploration and evaluation expenses of $28.1 million were recorded in the quarter (Q2 2014: $0.4 million). This primarily relates to the drilling of the unsuccessful Snømus exploration well in Norway in Q2 2015. Given the 1 January 2015 effective date for the divestment of the Norwegian business to MOL, the costs associated with the well were paid for by MOL as part of the transaction completion price adjustments.

ADMINISTRATION EXPENSES

Admin expenditure forecast to fall in 2015 due to on-going cost reduction measures

THREE MONTHS ENDED JUNE 30, 2015

Total administrative expenses decreased in the quarter to $1.9 million (Q2 2014: $3.8 million) primarily due to a reduction in the cost base of the business as a result of the lower oil price environment. Share based payment expenses have remained relatively flat with small fluctuations based on the timing of option grants and therefore the amortisation profile.

SIX MONTHS ENDED JUNE 30, 2015

Total administrative expenses decreased in the period to $5.5 million (H1 2014: $7.5 million) primarily due to the cost saving drive initiated as a result of the lower oil price environment. Additionally, around $2 million (pre-tax) of the total General and Administration ("G&A") cost relates to the cost of operating the Company's Norwegian office. Given the 1 January 2015 effective date for the divestment of the Norwegian business to MOL, these costs were paid for by MOL as part of the transaction completion price adjustments and as such have been fully reimbursed and will be absent going forward.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

THREE MONTHS ENDED JUNE 30, 2015

A foreign exchange loss of $2.5 million was recorded in Q2 2015 (Q2 2014: $2.2 million gain). The majority of the Company's revenue is US dollar denominated while expenditures are incurred predominantly in British pounds, although US dollar and Euro denominated costs are also incurred. General volatility in the GBP:USD exchange rate is the primary driver behind the foreign exchange gains and losses, with the rate moving from 1.48 at April 1, 2015 to 1.57 at June 30, 2015, with a material fluctuation within the quarter of between 1.46 and 1.59.

The Company recorded an overall $9.8 million loss on financial instruments for the quarter ended June 30, 2015 (Q2 2014: $11.2 million loss).

A $31.8 million gain was realised in Q2 2015, comprising $31.3 million relating to oil hedges maturing during the quarter with an average exercise price of $96 compared to an average Brent price of $62/bbl, combined with a $0.6 million gain on foreign exchange instruments, partially offset by a minor $0.1 million realised loss on interest rate swaps.

Offsetting the realised gain was a $41.7 million revaluation of instruments as at June 30, 2015, which relates to instruments still held at quarter end. This revaluation was primarily due to a loss on revaluation of commodity hedges of $48.3 million, partly offset by a gain on revaluation of foreign exchange instruments of $6.6 million. The loss on commodity instruments is due primarily to the realisation of the amounts noted above (i.e. where they are no longer still held at the period end), coupled with an decrease in value of the remaining instruments relative to the end of Q1 2015. The value of oil swaps and put options at the end of Q2 2015 has gone down based on the increase in the Brent oil forward curve ($61/bbl at end Q2 2015 compared to $54/bbl at the end of Q1 2015) and movement in the implied volatility at the end of the reporting periods.

This fair value accounting for financial instruments by its nature leads to volatility in the results due to the impact of revaluing the financial instruments at each reporting period end.

SIX MONTHS ENDED JUNE 30, 2015

A foreign exchange loss of $4.0 million was recorded in H1 2015 (H1 2014: $1.8 million gain) primarily due to volatility in the GBP:USD exchange rate with fluctuation between 1.46 and 1.59 during the period, closing at 1.57 on June 30, 2015.

The Company recorded an overall $19.3 million gain on financial instruments for the six month period ended June 30, 2015 (Q2 2014: $7.2 million loss).

A $110.5 million gain was realised in respect of commodity hedges, comprising $59.7 million relating to the accelerated oil hedging gain and $50.3 million relating to oil and gas hedges maturing during the period.

Offsetting the realised gain was the revaluation of instruments as at June 30, 2015, which relates to instruments still held at quarter end. This $91.2 million revaluation primarily related to a loss on revaluation of commodity hedges of $96.3 million, partly offset by a gain on revaluation of foreign exchange instruments of $5.0 million. The loss on commodity instruments was primarily due to the realisation of the amounts noted above (i.e. where they are no longer still held at the period end), partly offset by an increase in value of the remaining swaps and put options based on the movement in the forward curve and the implied volatility at the end of the reporting period.

FINANCE COSTS

THREE MONTHS ENDED JUNE 30, 2015

Finance costs increased to $10.8 million in Q2 2015 (Q2 2014: $5.7 million). This rise primarily reflects interest costs on the senior unsecured notes issued in July 2014. Drawn debt, including the senior notes, has increased from $616 million at the end of Q2 2014 to $813 million at the end of Q2 2015 following continued investment in the GSA development programme.

Accretion costs increased by $0.9 million compared to Q2 2014 due to higher decommissioning liabilities as at June 30, 2015 as a result of inclusion of the decommissioning liabilities associated with the Summit Assets.

SIX MONTHS ENDED JUNE 30, 2015

Finance costs increased to $20.9 million in H1 2015 (H1 2014: $12.0 million). As noted above, this rise primarily reflects increased interest costs and fees incurred in relation to the senior unsecured notes.

TAXATION

No UK tax anticipated to be payable prior to 2020

THREE MONTHS ENDED JUNE 30, 2015

A tax credit of $66.7 million was recognized in the quarter ended June 30, 2015 (Q2 2014: $7.7 million credit). This credit is a product of adjustments to the tax charge primarily relating to the UK Ring Fence Expenditure Supplement, the non-taxable gain on disposal of Norway, and additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac (refer to note 25 in the Q2 2015 Consolidated Financial Statements).

As a result of the above factors, the loss before tax of $26.8 million becomes a profit after tax of $39.9 million (Q2 2014: $0.7 million profit).

SIX MONTHS ENDED JUNE 30, 2015

A tax credit of $32.2 million was recognised in the six months ended June 30, 2015 (H1 2014: $19.5 million credit). This amount includes $75.7 million credit relating to UK and Norway taxation which is a product of the taxable loss generated and adjustments to deferred tax charge primarily relating to the UK Ring Fence Expenditure Supplement, the non-taxable gain on disposal of Norway and additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac (refer to note 25 in the Q2 2015 Consolidated Financial Statements).

This credit is offset by a charge of $41.5 million relating to changes in the Supplementary Charge and Petroleum Revenue Tax ("PRT") rates enacted in the period.

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. The reduction was enacted on 30 March 2015. This resulted in a charge of $52.1 million relating to deferred Corporation Tax. This was partially offset by a credit of $10.6 million relating to the impact in the change of the rate of PRT from 50% to 35% on the deferred PRT liability in the balance sheet.

As a result of the above factors, the loss before tax of $18.4 million becomes a profit after tax of $13.8 million (H1 2014: $17.0 million profit). Adjusting for the impact of the change in tax rates would give a profit after tax of $55.3 million.

CAPITAL INVESTMENTS

Continued significant investment in GSA development in 2015

Capital additions to development and production ("D&P") assets totalled $89.8 million in H1 2015. These relate primarily to the execution of the GSA development (as described above) and the development of the Ythan field.

Capital additions to E&E assets in H1 2015 were $28.9 million predominantly relating to drilling of the Snømus prospect, the costs of which have been reimbursed upon completion of the sale of the Norwegian operations.

Total capital expenditure in H1 2015 net of the associated Norwegian tax receivable of $20.9 million was $98.5 million.

WORKING CAPITAL

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

As at June 30, 2015, Ithaca had a net working capital balance of $59.8 million, including an unrestricted cash balance of $25.4 million invested in money market deposit accounts with BNP Paribas. Substantially all of the accounts receivable are current, being defined as less than 90 days. The Company regularly monitors all receivable balances outstanding in excess of 90 days. No credit loss has historically been experienced in the collection of accounts receivable.

Working capital movements are driven by the timing of receipts and payments of balances and fluctuate in any given quarter. 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.

Net working capital has decreased over the six month period to 30 June 2015 mainly as a result of crystallisation of the cash receipt of a proportion of the oil price hedges held at period end. This was partially offset by increased settlement of payables associated with the on-going GSA development programme.

As noted in the Q1 2015 Management Discussion and Analysis, in April 2015 Trap Oil plc ("Trap"), a 15% working interest partner in the Ithaca operated Athena field, announced that it thought highly likely insolvency proceedings, such as administration or liquidation, would commence. Subsequently, the Athena co-venturers and other principal creditors of Trap entered into a settlement agreement with the company in order to implement an optimal solution for protecting the financial interests of the creditors. In return for the payment of £1.6 million to the Athena co-venturers, all of Trap's future field liabilities will be met by the remaining co-venturers, with repayment of these liabilities being met through the receipt of 60% of any sale proceeds arising from Trap's existing licence interests, up to 125% of the outstanding liabilities. As at June 30, 2015, Ithaca has booked no additional liabilities in relation to this and does not expect any material liabilities to arise.

CAPITAL RESOURCES

Strong liquidity - total debt funding capacity of $950 million in place

DEBT FACILITIES

At June 30, 2015, following the bank debt facilities simplification and extension, Ithaca had two UK bank debt facilities available, being the $575 million senior RBL Facility and the $75 million junior RBL Facility, both due September 2018 (further information is provided in the "Corporate Activities" section above). The Company also had $300 million senior unsecured notes, due July 2019. At the end of Q2 2015, the Company had unused UK bank debt facilities totalling approximately $137 million (Q2 2014: $160 million), with approximately $513 million drawn under the RBL facility.

The Company's bank debt facilities are forecast to be sufficient to ensure that adequate financial resources are available to cover anticipated future commitments when combined with existing cash balances and forecast cash from operations.

The Company was in compliance with all its relevant financial and operating covenants during the quarter. The key covenants in the senior and junior RBL facilities are:

· A corporate cashflow projection showing total sources of funds must exceed total forecast uses of funds for the later of the following 12 months or until forecast first oil from the Stella field.

· 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 must not fall 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 must not fall below 1.05:1.

There are no financial maintenance covenant tests associated with the senior notes.

Norwegian tax refund facility repaid and retired

NORWEGIAN TAX REFUND FACILITY

Following completion of the transaction with MOL plc for the sale of the Company's Norwegian business on 8 July 2015, the Company's NOK 600 million Norwegian tax refund facility was fully repaid and retired.

H1 2015 CASHFLOW MOVEMENTS

During the six months ended June 30, 2015 there was a cash inflow from operating, investing and financing activities of approximately $6 million (H1 2014 outflow of $13 million); as set out in the following graph.

Cashflow from operations

Cash generated from operating activities was $140 million primarily attributable to cash generated from the Dons , Causeway Area, Cook and Wytch Farm fields, as well as the acceleration of a portion of the accumulated oil hedging gain received during the Q1 2015.

Cashflow from financing activities

Cash generated from financing activities was $44 million primarily due to drawdowns of the debt facilities in H1 2015 ($55.2 million), less interest and bank charges ($11.3 million).

Cashflow from investing activities

Cash used in investing activities was $118 million, primarily related to further capital expenditure on the GSA development, together with Ythan well costs.

COMMITMENTS

The Company's commitments relate primarily to completion of the capital investment programme on the GSA development, in addition to more limited commitments associated with the Wytch Farm field well workover programme. 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 June 30, 2015.

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 quarter.

* Exposure to increase in oil price capped at $102 / bbl

FOREIGN EXCHANGE

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

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 quarter, the Company has hedged interest payments on the following:

QUARTERLY RESULTS SUMMARY

1 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 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 June 30, 2015 Ithaca had 329,518,620 common shares outstanding along with 21,553,220 options outstanding to employees and directors to acquire common shares.

In Q2 2015, the Company's Board of Directors granted 950,000 options at a weighted average exercise price of C$1.04. 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$1.05) on 30 June 2015. US$:CAD$ 0.8093 on 30 June 2015

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. 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. Following the sale of the Company's Norwegian operations, Ithaca Petroleum Norge AS has been divested and as of 3Q 2015, will not feature in the financial results of the Company.

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 June 30, 2015, 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 June 30, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) 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 June 30, 2015, there were no changes in the Company's internal control over financial reporting that occurred during the quarter ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

CHANGES IN ACCOUNTING POLICIES

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.

"Net 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 June 30, 2015, finance lease assets of $31.4 million and related liabilities of $31.2 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 Q2 2015 was $0.0 million (Q2 2014: $0.1 million). These transactions are in the normal course of business and are conducted on normal commercial terms with consideration comparable to those charged by third parties.

As at June 30, 2015 the Company had a loan receivable from FPF-1 Ltd, an associate of the Company, for $58.8 million (December 31, 2014: $58.3 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 for the year ended December 31, 2014, (the "AIF") filed on SEDAR at www.sedar.com.

Commodity Price Volatility

RISK: 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.

MITIGATIONS: 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

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

MITIGATIONS: 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 pounds sterling to settle sterling costs which will be repaid from surplus sterling generated revenues derived from Stella gas sales.

Interest Rate Risk

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

MITIGATIONS: To mitigate the fluctuations in interest rates, the Company routinely reviews the associated cost exposure and periodically executes hedges to lock in interest rates.

Debt Facility Risk

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.

MITIGATIONS: The financial tests necessary to draw down upon the Facilities needed were met during the period.

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

Financing Risk

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.

MITIGATIONS: 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

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.

MITIGATIONS: 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

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.

MITIGATIONS: 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

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.

MITIGATIONS: 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

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.

MITIGATIONS: 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

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

MITIGATIONS: 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

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.

MITIGATIONS: 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

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

MITIGATIONS: 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 dispositions 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 "forecasts", "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 peak net drawn debt requirement prior to Stella start up;

· The timing of Stella first hydrocarbons;

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

· The realisation of anticipated benefits from acquisitions and dispositions;

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

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

· The Company's future operating and financial results;

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

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

· Production rates;

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

· Targeted production levels; and

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

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

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

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

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

· The Company's development plan for its properties 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 and dispositions;

· 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 August 12, 2015. The Q2 2015 results have been compared to the results of the comparative period in 2014. This MD&A should be read in conjunction with the Company's unaudited consolidated financial statements as at June 30, 2015 and 2014 and with the Company's audited consolidated financial statements as at December 31, 2014 together with the accompanying notes and AIF for the year ended December 31, 2014. These documents, and additional information regarding Ithaca, are available electronically from the Company's website (www.ithacaenergy.com) or SEDAR profile at www.sedar.com.

Consolidated Statement of Income

For the three and six months ended 30 June 2015 and 2014

(unaudited)

Three months ended 30 June

Six months ended 30 June

Note

2015

US$'000

2014

US$'000

2015

US$'000

2014

US$'000

Revenue

5

 59,152

99,931

129,527

199,571

- Operating costs

(29,499)

(51,896)

(57,622)

(93,161)

- Oil purchases

-

(373)

-

(792)

- Movement in oil and gas inventory

3,068

15,596

(13,123)

3,735

- Depletion, depreciation and amortisation

(31,702)

(51,307)

(62,259)

(83,772)

Cost of sales

(58,133)

(87,980)

(133,004)

(173,989)

Gross Profit/ (Loss)

1,019

11,951

(3,477)

25,582

Exploration and evaluation expenses

10

(28,057)

(446)

(29,101)

(2,454)

Gain on disposal

32

25,237

-

25,237

2,190

(Loss)/Gain on financial instruments

27

(9,831)

(11,203)

19,291

(7,241)

Impairment of Assets

-

-

-

(2,895)

Administrative expenses

6

(1,906)

(3,846)

(5,491)

(7,544)

Foreign exchange

(2,513)

2,203

(4,009)

1,830

Finance costs

7

(10,775)

(5,747)

(20,895)

(12,021)

Interest income

-

17

50

42

(Loss) Before Tax

(26,826)

(7,071)

(18,395)

(2,511)

Taxation

25

66,714

7,730

32,203

19,536

Profit After Tax

39,888

659

13,808

17,025

Earnings per share

Basic

24

0.12

0.00

0.04

0.05

Diluted

24

0.12

0.00

0.04

0.05

Consolidated Statement of Financial Position

(unaudited)

30 June

31 December

Note

2015

US$'000

2014

US$'000

ASSETS

Current assets

Cash and cash equivalents

25,423

19,381

Accounts receivable

8

284,112

266,747

Deposits, prepaid expenses and other

1,684

1,140

Inventory

9

17,813

27,481

Derivative financial instruments

28

59,967

150,760

388,999

465,509

Non-current assets

Long-term receivable

30

58,800

58,338

Long-term Norwegian tax receivable

8

-

7,032

Long-term inventory

9

8,126

8,126

Investment in associate

13

18,337

18,337

Exploration and evaluation assets

10

44,576

89,844

Property, plant & equipment

11

1,462,209

1,435,209

Deferred tax assets

192,901

139,266

Goodwill

12

137,114

137,114

1,922,063

1,893,266

Total assets

2,311,062

2,358,775

LIABILITIES AND EQUITY

Current liabilities

Trade and other payables

15

(329,242)

(392,131)

Exploration obligations

16

(4,370)

(5,431)

Onerous contracts

17

(1,254)

(21,635)

(334,866)

(419,197)

Non-current liabilities

Borrowings

14

(800,115)

(784,859)

Decommissioning liabilities

18

(217,604)

(213,105)

Other long term liabilities

19

(92,123)

(92,020)

Contingent consideration

21

(4,000)

(4,000)

Derivative financial instruments

28

(1,521)

(587)

(1,115,363)

(1,094,571)

Net assets

860,833

845,007

Shareholders' equity

Share capital

22

551,632

551,632

Share based payment reserve

23

21,252

19,234

Retained earnings

287,949

274,141

Total equity

860,833

845,007

The financial statements were approved by the Board of Directors on 12 August 2015 and signed on its behalf by:

"Les Thomas"

Director

 "Alec Carstairs"

Director

The accompanying notes on pages 6 to 22 are an integral part of the financial statements.

Consolidated Statement of Changes in Equity

(unaudited)

Share Capital

Share based

payment

reserve

Retained Earnings

Total

US$'000

US$'000

US$'000

US$'000

Balance, 1 Jan 2014

535,716

19,254

298,676

853,646

Share based payment

-

3,280

-

3,280

Options exercised

12,393

(4,827)

 -

7,566

Profit for the period

 -

 -

17,025

17,025

Balance, 30 June 2014

548,109

17,707

315,701

 881,517

Balance, 1 Jan 2015

551,632

19,234

274,141

845,007

Share based payment

 -

2,018

 -

2,018

Profit for the period

 -

 -

13,808

13,808

Balance, 30 June 2015

551,632

21,252

287,949

860,833

Consolidated Statement of Cash Flow

For the three and six months ended 30 June 2015 and 2014

(unaudited)

Three months ended 30 June

Six months ended 30 June

2015

US$'000

2014

US$'000

2015

US$'000

2014

US$'000

CASH PROVIDED BY (USED IN):

Operating activities

Loss Before Tax

(26,826)

(7,071)

(18,395)

(2,511)

Adjustments for:

Depletion, depreciation and amortisation

11

31,702

51,307

62,259

83,771

Exploration and evaluation expenses

 10

28,057

446

29,101

2,454

Impairment

-

-

-

2,895

Onerous contracts

17

(8,611)

-

(20,002)

-

Share based payment

209

337

389

766

Loan fee amortisation

1,881

923

3,058

1,849

Revaluation of financial instruments

27

41,661

7,381

91,216

4,703

Gain on disposal

32

(25,237)

-

(25,237)

(2,190)

Accretion

2,261

1,305

4,499

2,610

Bank interest & charges

6,632

3,504

13,339

7,483

Cashflow from operations

51,729

58,132

140,227

101,830

Changes in inventory, receivables and payables relating to operating activities

(4,169)

(13,255)

(25,086)

22,148

Petroleum Revenue Tax paid

(2,711)

-

(4,443)

-

Net cash from operating activities

44,849

44,877

110,698

123,978

Investing activities

Capital expenditure

(57,700)

(106,020)

(117,946)

(234,725)

Loan to associate

(679)

(20,763)

(462)

(20,854)

Proceeds on disposal

 -

-

-

2,190

Changes in receivables and payables relating to investing activities

(14,130)

58,435

(29,293)

(59,971)

Net cash used in investing activities

(72,509)

(68,348)

(147,701)

(313,360)

Financing activities

Proceeds from issuance of shares

-

517

-

7,567

Derivatives

-

-

-

(1,315)

Loan draw down

28,908

35,914

55,188

171,865

Bank interest & charges

(1,732)

(3,024)

(11,311)

(5,941)

Net cash from financing activities

27,176

33,407

43,877

172,176

Currency translation differences relating to cash

(2)

1,671

(832)

4,524

Increase / (decrease) in cash and cash equiv.

(486)

11,607

6,042

(12,682)

Cash and cash equivalents, beginning of period

25,909

39,146

19,381

63,435

Cash and cash equivalents, end of period

25,423

50,753

25,423

50,753

Three months ended 30 June

Six months ended 30 June

2015

US$'000

2014

US$'000

2015

US$'000

2014

US$'000

Oil sales

57,404

97,231

125,675

193,833

Gas sales

1,841

1,463

3,240

3,519

Condensate sales

136

116

289

135

Other income

(229)

1,121

323

2,084

59,152

99,931

129,527

199,571

Three months ended 30 June

Six months ended 30 June

2015

US$'000

2014

US$'000

2015

US$'000

2014

US$'000

General & administrative

(1,697)

(3,507)

(5,102)

(6,778)

Share based payment

(209)

(339)

(389)

(766)

(1,906)

(3,846)

(5,491)

(7,544)

Three months ended 30 June

Six months ended 30 June

2015

US$'000

2014

US$'000

2015

US$'000

2014

US$'000

Bank interest and charges

(2,117)

(3,161)

(4,627)

(7,140)

Senior notes interest

(3,444)

-

(7,349)

-

Finance lease interest

(264)

-

(530)

-

Non-operated asset finance fees

(27)

(38)

(51)

(101)

Prepayment interest

(781)

(310)

(781)

(310)

Loan fee amortisation

(1,881)

(923)

(3,058)

(1,850)

Accretion

(2,261)

(1,315)

(4,499)

(2,620)

(10,775)

(5,747)

(20,895)

(12,021)

30 June

2015

US$'000

31 Dec

2014

US$'000

Norwegian tax receivable - non-current

-

7,032

Norwegian tax receivable - current

-

25,362

Norwegian disposal consideration

34,232

-

Trade debtors

158,252

229,248

Accrued income

91,628

12,137

284,112

273,779

30 June

2015

US$'000