Q1-2015 Financial Results

HIGHLIGHTS FIRST QUARTER 2015

Solid underlying cashflow generation - underpinned by lower unit operating expenditure and significant hedging protection

· Q1 2015 production of 12,489 barrels of oil equivalent per day ("boepd"), in line with 2015 production guidance of approximately 12,000 boepd (95% oil)

· $99.9 million cashflow from ongoing operations(1), including $59.7 million from the previously announced one-off acceleration of oil price hedges

· Operating costs of under $35/boe, approximately 30% lower than 2014 annual average unit operating expenditure

· Adjusted earnings of $15.4 million, excluding a non-cash accounting tax charge of $41.5 million resulting from a reduction in UK tax rates

· Quarterly cashflow per share $0.27 (Q1 2014: $0.13) and adjusted earnings per share $0.05 (Q1 2014: $0.05)

· Over 2 years of oil hedging in place - average of 6,800 barrels of oil per day ("bopd") at $74/bbl until June 2017

· Brent breakeven price for the existing producing asset base of under $10/bbl until Stella start-up

· Net drawn debt of $780.6 million at 31 March 2015 ($763.3 million at 31 December 2014), excluding the Norwegian tax rebate facility

· UK tax allowances pool of $1,524 million at 31 March 2015 (Q4 2014: $1,496 million)

Bank debt facilities "right sized" to meet pre-Stella start-up requirements

· Semi-annual borrowing base review completed in April 2015, with total bank debt facilities sized at $650 million, comprising a senior Reserve Based Lending ("RBL") facility of $575 million and a junior RBL facility of $75 million

· Replacement of the former corporate facility with a junior RBL removes the use of historic financial covenant tests from the debt facilities and ensures the funding capacity is reflective of the future value of the Company's assets

· Total Company debt funding capacity of $950 million with inclusion of the $300 million senior unsecured notes due July 2019

· Forecast peak debt requirement prior to Stella start-up of $825-850 million in the second quarter of 2015, resulting in headroom of over $100 million

Norway sale - accelerated monetisation of non-core operations while retaining upside exposure to wells

· Agreement executed for sale of Norwegian operations 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

· Transaction expected to complete in Q3 2015, resulting in a net initial cash receipt of approximately $30 million post Norwegian debt repayment and working capital adjustments - funds to reduce RBL drawings

· Transaction marks completion of the highly successful monetisation of the non-core exploration elements of the licence interests transferred as part of the Valiant Petroleum acquisition in 2013

Solid progress being made on all remaining aspects of the GSA development programme

· Development drilling programme completed in April 2015. With the strong flow test results achieved on the Stella Ekofisk well, the 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

· Construction activities on the FPF-1 remain focused on delivering mechanical completion as planned in Q3 2015, with manning levels on the vessel at historic highs over recent weeks

· 2015 subsea infrastructure installation campaign progressing to plan, with the mid-water arch and Single Anchor Loading oil export structures now installed and northern drill centre wells tied in

SUMMARY STATEMENT OF INCOME

(1) Average realised price before hedging

(2) Revenue less stock movements

(3) Opex plus forex losses

(4) Cashflow from ongoing operations of $99.9m less $11.4M onerous contract provision release = total cashflow from operations of $88.5M

(5) Based on total cashflow from operations of $88.5M

(6) 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

(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 resources, 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

Extended and simplified bank debt facilities - "right sized" for the Company's funding requirements ahead of Stella start-up

BANK DEBT FACILITIES EXTENSION

In April 2015 the Company completed its semi-annual borrowing base bank review and put in place total bank debt facilities sized at $650 million, comprising a senior Reserve Based Lending ("RBL") facility of $575 million and a junior RBL facility of $75 million. When combined with the existing $300 million senior unsecured notes due July 2019, the Company's debt facilities provide significant funding headroom ahead of first hydrocarbons from the Greater Stella Area ("GSA") in the second quarter of 2016.

As part of the borrowing base review the tenor of the senior RBL facility has been extended as planned to September 2018, thereby aligning the maturity of both bank debt facilities. The replacement of the former corporate facility with a junior RBL has also simplified the overall debt structure, removing the use of historic financial covenant tests from the facilities and ensuring the total bank funding capacity is reflective of the future value of the Company's assets.

The $650 million bank debt 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. The combined interest rate of the two facilities, fully drawn, is LIBOR +3.4% (previously 3.2%) prior to Stella coming on-stream, stepping down to LIBOR +2.9% (previously 2.9%) after Stella production has been established. This means the overall fully drawn weighted average debt costs of the business including the unsecured senior notes remains under 5%.

Significant value generated from the sale of the restructured Norwegian business transferred as part of the Valiant acquisition in April 2013 - net initial consideration equates to ~CAD$0.11 per share

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.

The transaction has an effective date of 1 January 2015 and is expected to complete in the third quarter of 2015. Completion of the transaction is subject to the approval of the Norwegian Ministry of Petroleum and Energy.

After repayment of the Company's Norwegian exploration financing facility and forecast working capital adjustments, the sale is anticipated to result in an initial net cash receipt of approximately $30 million, which will be used to offset drawings under the Company's existing bank debt facility. The potential future bonus payments depend on successful discoveries being drilled on Ithaca Norge's existing licence portfolio between 2015 and 2017, with any payments based on a sliding scale depending on discovery size.

The Norwegian portfolio has no production or reserves associated with the licence interests.

This transaction marks completion of the highly successful monetisation of the non-core exploration related elements of the licence interests transferred to Ithaca as part of the Valiant Petroleum plc acquisition in April 2013. While these aspects of the Valiant portfolio were treated as liabilities in the acquisition, substantial value has been generated through the Norwegian sale and the various UK farm-outs that were completed in 2013, along with the highly efficient removal of all operational overlaps within three months of the acquisition completion.

PRODUCTION & OPERATIONS

35% increase in production compared to Q1 2014, with Q1 2015 production performance in line with guidance

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

Material Athena field cost reduction secured via revised FPSO contract terms

PRODUCTION

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

Average Q1 2015 production was 12,489 boepd, 93% oil. This represents a 35% increase on the same quarter in 2014 (Q1 2014: 9,222 boepd). This significant increase is attributable to inclusion of additional production from the assets acquired from Sumitomo Corporation (the "Summit Assets"), which were added to the portfolio in July 2014, and stronger uptime performance across the asset base during the winter period.

Production in the second quarter of 2015 ("Q2 2015") is expected to be broadly in line with that of the first quarter of the year. Production is scheduled to commence from the Ythan field during the second quarter, partially offsetting a reduction in volumes associated with commencement of an approximately three week planned maintenance shutdown of the Sullom Voe Terminal ("SVT") at the end of the quarter; the terminal serves the Company's Dons and Causeway Area fields. Completion of the SVT shutdown during the third quarter ("Q3 2015"), along with an approximately two month planned shutdown of the Cook field for continued execution of FPSO life extension works, means that production in Q3 2015 is forecast to be below the average guidance level for the year.

OPERATIONS

The Company has made good operational progress in Q1 2015, having completed a number of this year's key activities. 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 was brought into service and production from the Pierce field commenced following completion of the floating production, storage and offloading ("FPSO") vessel modification works required for tie-in of the third party Brynhild field.

Drilling operations on the Ythan development well were completed in April 2015 and the rig demobilised from the field. The final remaining activity to be completed prior to the start-up of production from the field is installation of a subsea flowline between the wellhead and the production manifold. A diving support vessel has been contracted and this work is expected to be completed in the coming weeks.

Good progress continues to be made on the Wytch Farm well workover campaign, which is scheduled to continue over the course of the year.

ATHENA FPSO LEASE

As previously announced, in Q1 2015 the Company renegotiated the contract for the lease of the BW Athena FPSO. Under the terms of the amended contract, the Athena co-venturers will make advanced payment of an FPSO demobilisation fee (approximately $4.5 million net to Ithaca, payable in July 2015) and from the end of the primary contract term in June 2015, the vessel day rate will no longer apply with the co-venturers and BW Offshore instead sharing 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.

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. Significant progress has been made on the FPF-1 modifications programme, the critical path item for delivering first hydrocarbons from the GSA hub. 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 successfully completed in April 2015

Drilling Programme

The planned five well Stella development drilling programme was completed in April 2015 when the ENSCO 100 rig was demobilised from the field. The wells have all been successfully cleaned up and suspended in a manner that allows the wells to be brought on to production without the requirement for any further intervention activity once the FPF-1 floating production facility is on location and hooked up.

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.

FPF-1 manning levels at historic highs, with good progress being made towards delivering mechanical completion of the vessel as planned in Q3 2015

FPF-1 Modification Works

The key focus of the remaining FPF-1 modification works being completed by Petrofac in the Remontowa yard in Poland is close out of the construction programme and completion of the vessel commissioning activities required to enable sail-away of the vessel to the field in Q1 2016.

Mechanical completion is scheduled for the third quarter of 2015, reflecting the incentivised mechanical completion schedule agreed between Petrofac and the Remontowa yard. 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 levels on the vessel have been at historic highs over recent weeks. All the main equipment has been positioned on the vessel, pipework installation operations are nearing completion and over 70% of the electrical and instrumentation cabling has been installed. The main outstanding construction activities are completion of pipework pressure testing, electrical and instrumentation cable glanding and termination and instrumentation device installation. The transfer of vessel sub-systems from the construction phase for pre-commissioning has commenced, as preparations continue for the start of commissioning operations.

2015 subsea infrastructure installation programme progressing to plan

Subsea Infrastructure WORKS

The remaining subsea infrastructure installation works are scheduled to be completed in the second and third quarters of 2015, leaving only the FPF-1 installation and hook-up activities to be undertaken when the vessel arrives on location in 2016.

Offshore operations recommenced as planned in April 2015. The Single Anchor Loading ("SAL") structures that will be used for exporting oil from the FPF-1 to shuttle tankers and the mid-water arch over which the risers and umbilicals connecting the subsea infrastructure to the FPF-1 will be positioned have now been installed and tie-in of the two northern drill centre wells has been completed.

The tie-in of the recently completed Stella Ekofisk well at the main drill centre is scheduled to be completed shortly. Following this, the main outstanding activity will be installation of the 3 kilometre oil export pipeline from the FPF-1 riser base to the SAL structures, which is scheduled to be undertaken using Technip's Apache II pipelay vessel in the third quarter of the year.

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 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 $79 million at an annualised 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.

OPERATING EXPENDITURE

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

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 provided by the oil price hedging that has been executed since the start of the year, 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.

The results of the various supply chain and overhead cost reduction initiatives are starting to positively impact the financial results, although it will naturally take some time for the final impact of some measures to fully feed through to unit operating costs. Nevertheless, when combined with the cessation of operations at the high cost Beatrice and Jacky fields and the retransfer of the Beatrice facilities to Talisman during the quarter, the Q1 2015 financial results show a step change in unit operating costs. More specifically, underlying unit operating costs have reduced by 33% to $33.3/boe compared to the same period in 2014 (Q1 2014: $49.7/boe). Full year unit operating costs are expected to average between $35 - $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

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 and asset maintenance activities.

The 2015 capital expenditure programme is forecast to be weighted towards the first half of the year driven by completion of drilling operations on Stella and Ythan, with the rigs for both wells having been demobilised in April 2015, and the commencement of the remaining GSA subsea infrastructure installation works in Q2 2015. This programme is forecast to be fully funded on an annual basis by operating cashflows generated from the Company's 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.

Given the anticipated capital expenditure phasing for the year, peak net drawn debt prior to Stella start-up is forecast to be in the range of $825-850 million in the second quarter of 2015. Thereafter, the Company is set to commence deleveraging the business.

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.

Q1 2015 RESULTS OF OPERATIONS

REVENUE

Revenue decreased by $29.2 million in Q1 2015 to $70.4 million (Q1 2014: $99.6 million). This 30% reduction was driven by a decrease of $50/bbl or 46% in the pre-hedging realised oil price, partly offset by a 31% increase in underlying sales volumes.

Sales volumes increased in Q1 2015 primarily due to the inclusion of production from the Summit Assets. This increase was partially offset by the absence of Beatrice and Jacky sales volumes in Q1 2015 following the re-transfer of the Beatrice facilities to Talisman during the quarter, combined with the exclusion of Athena and Anglia revenues, previously accounted for as part of the onerous contracts provision in 2014. If revenues were however to be adjusted to include Athena and Anglia, there would be a modest increase in Q1 2015 revenue to $73.1 million.

The significant fall in Brent from $108/bbl in Q1 2014 to $54/bbl in Q1 2015 drove a decrease in average realised oil prices from $108/bbl in Q1 2014 to $58/bbl in Q1 2015. This decrease was nonetheless partially offset by a realised hedging gain of $16/bbl in the quarter, excluding the benefit of the accelerated hedging reset referred to in the "Foreign Exchange and Financial Instruments" section below.

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.

COST OF SALES

Cost of sales decreased in Q1 2015 to $74.9 million (Q1 2014: $86.0 million) driven by decreases in operating costs and depletion, depreciation and amortisation ("DD&A").

Reported operating costs decreased in the quarter to $28.1 million (Q1 2014: $41.3 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 $9.0 million of Athena and Anglia operating costs which were provided for as an onerous contract provision in Q4 2014. Additionally, there have been significant cost savings realised across the portfolio as a result of various supply chain cost reduction initiatives.

The underlying Q1 2015 unit operating costs, after adding back the previously provided for Athena and Anglia operating costs (onerous contract provision booked in 2014), was $33.3/boe. This represents a reduction of over 30% compared to the rate of $49.7/boe in Q1 2014. Full year unit operating costs are expected to average between $35 - $40/boe.

The unit DD&A rate for the quarter decreased significantly to $27/boe (Q1 2014: $39/boe), resulting in the DD&A expense for the quarter reducing to $30.6 million (Q1 2014: $32.5 million). This reduction was primarily due to 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) 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 additional impairment write downs booked in 2014 as a consequence of the change in oil price environment.

An oil and gas inventory movement of $16.2 million was charged to cost of sales in Q1 2015 (Q1 2014 charge of $11.9 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. In Q1 2015 more barrels of oil were sold (1,218kbbls) than produced (1,045kbbls), mainly as a result of the timing of Cook field liftings, as well as being impacted by the lifting pattern across various other fields.

IMPAIRMENT CHARGES AND EXPLORATION & EVALUATION EXPENSES

Exploration and evaluation expenses of $1.0 million were recorded in the quarter (Q1 2014: $2.0 million) following the relinquishment of the Piper Isles license awarded in the 27th licensing round in 2012.

The impairment charge in Q1 2014 was as a result of the planned re-transfer of the Beatrice facilities to Talisman in Q1 2015.

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 were therefore made in 2014 for the Athena and Anglia fields, both of which were 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, as well as provision for the costs associated with the re-transfer of the Beatrice facilities. $11.7 million of the provision was released in Q1 2015.

ADMINISTRATION EXPENSES

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

Total administrative expenses decreased in the quarter to $3.6 million (Q1 2014: $3.7 million) primarily due to a reduction in share based payment expenses as a result of the timing of option grants: no new option awards were granted in Q1 2015 whereas 2013 option awards were granted in January 2014, resulting in higher amortisation expense in the period. G&A costs remained relatively flat quarter on quarter. However, around $1.3 million (pre-tax) of the total General and Administration ("G&A") cost relates to the cost of operating the Company's Norwegian office and this will be fully reimbursed from 1 January 2015 as part of the sale of the Norwegian business, with the transaction expected to complete in Q3 2015.

In addition to the ultimate removal of the Norwegian office costs from the start of the year, total G&A costs are also anticipated to reduce further through 2015 as a result of various actions that have been taken to adjust the cost base of the business in response to the lower oil price environment.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

A foreign exchange loss of $1.5 million was recorded in Q1 2015 (Q1 2014: $0.4 million loss). 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 (GBP:USD at January 1, 2015: 1.55. GBP:USD at March 31, 2015: 1.48 with fluctuation between 1.47 and 1.56 during the quarter).

The Company recorded an overall $29.1 million gain on financial instruments for the quarter ended March 31, 2015 (Q1 2014: 4.0 million gain).

A $78.8 million gain was realised in respect of commodity hedges, comprising $59.7 million relating to the previously mentioned accelerated oil hedging gain and $19.0 million relating to oil hedges maturing during the quarter. A minor $0.1 million realised loss was incurred on interest rate swaps.

Offsetting the realised gain was the revaluation of instruments as at March 31, 2015, which relates to instruments still held at quarter end. This $49.6 million revaluation primarily related to a loss on revaluation of commodity hedges due to the realisation of the amounts noted above (i.e. where they are no longer still held at the period end), offset by an increase in value of the remaining 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. For example, given current oil hedges of 5.6 million barrels, an increase in oil prices by $10/bbl to around $64/bbl compared to a close of $54 on March 31 2015, would result in a future unrealised non-cash mark-to-market loss in the Income Statement of over $50 million.

FINANCE COSTS

Finance costs increased to $10.1 million in Q1 2015 (Q1 2014: $6.3 million). This rise primarily reflects increased interest costs and fees incurred in relation to additional drawings under the Company's RBL debt facility combined with interest on the senior unsecured notes. Debt drawn, including the bond issue, has increased from $580 million at the end of Q1 2014 to $824 million at the end of Q1 2015 following continued investment in the GSA development programme. Accretion costs have also increased $0.9 million compared to Q1 2014 due to higher decommissioning liabilities as at March 31, 2015 as a result of inclusion of the decommissioning liabilities associated with the Summit Assets.

TAXATION

No UK tax anticipated to be payable prior to 2020

A tax charge of $34.5 million was recognized in the quarter ended March 31, 2015 (Q1 2014: $11.8 million credit). This charge is primarily driven by the 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 has resulted in a charge of $52.1 million relating to deferred Corporation Tax. This is 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 at 31 March 2015. Absent these rate changes, there was an overall tax credit of $7.0m in the quarter.

$8.1 million is a non-cash credit relating to UK and Norway taxation and is a product of adjustments to the tax charge primarily relating to the UK Ring Fence Expenditure Supplement, 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).

The additional charge of $1.1 million in Q1 2015 relates to PRT of 50% payable on cashflows generated by the Company's Wytch Farm field interest. As noted above, in the March 2015 budget, the UK government announced that the rate of PRT would reduce to 35% effective from 1 January 2016. While this impacts the deferred PRT liability at 31 March 2015, the current PRT charge remains at 50% throughout 2015.

As a result of the above factors, the profit before tax of $8.4 million becomes a loss after tax of $26.1 million (Q1 2014: $16.4 million profit). Adjusting for the impact of the change in tax rates would give a profit after tax of $15.4 million.

No Corporation Tax or Supplementary Charge is expected to be payable prior to 2020 relating to UK upstream oil and gas activities as a result of the $1,524 million of UK tax allowances available to the Company. The change in the Corporation Tax rate announced in March 2015 does not impact the anticipated timeframe in which the Company will become tax paying.

CAPITAL EXPENDITURE

Continued significant investment in GSA development in 2015

Capital additions to development and production ("D&P") assets totalled $55 million in Q1 2015. These relate primarily to the execution of the GSA development (as described above) and the drilling of the Ythan well.

Capital additions to E&E assets in Q1 2015 were $5.0 million, offset by a $0.9 million release of the E&E liability, resulting in a net addition of $4.1 million. Expenditure was primarily focused on the Norwegian portfolio, the costs of which will be reimbursed upon completion of the sale of the Norwegian operations, anticipated in Q3 2015. The E&E expenditure (excluding any provision releases) net of the 78% Norwegian tax refund is $1.7 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 March 31, 2015, Ithaca had a net working capital balance of $73.4 million including an unrestricted cash balance of $25.9 million. Available cash has been, and is currently, invested in money market deposit accounts with BNP Paribas.

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. 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 March 31, 2015 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. On April 23, 2015, Trap Oil Group PLC, an Athena joint venture partner (15% working interest), announced that it had insufficient resources to continue operating beyond the short term and that in the absence of a viable funding solution, its board considered it highly likely that insolvency proceedings, such as administration or liquidation, would commence. At March 31, 2015, Ithaca has booked no additional liabilities in relation to this and does not expect any material liabilities to arise.

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

DEBT FACILITIES

At March 31, 2015, 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, due July 2019. At the end of Q1 2015, the Company had unused UK bank debt facilities totalling approximately $208.2 million (Q1 2014: $197 million), with approximately $501.8 million drawn under the RBL facility.

Subsequent to the quarter end, the Company's bank debt facilities were extended and simplified. The maturity of the RBL Facility was extended to September 2018 to better synchronise its duration with the Stella start-up schedule and the corporate facility was replaced with a junior RBL facility. The facilities have been sized at a total of $650 million, being $575 million for the senior RBL and $75 million for the junior RBL. When combined with the $300 million senior unsecured notes, this provides the Company with total debt funding capacity of $950 million (further information is provided in the "Corporate Activities" section above).

The revised 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 RBL facility (pre and post extension and amendment) 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 under the senior notes.

The principal covenants under the undrawn Corporate Facility were:

· 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.

From April 2015 these corporate facility covenants have been replaced by the RBL covenants noted above given the replacement of the facility with the junior RBL.

Norwegian tax refund facility to be paid off and retired upon completion of Norway transaction

NORWEGIAN TAX REFUND FACILITY

Additionally at March 31, 2015, the Company had a Norwegian tax refund facility (the "Norwegian Tax Refund 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. Approximately $22.5 million was drawn on the facility as at March 31, 2015. The key covenant in the Norwegian Tax Refund Facility is that the Norwegian subsidiaries must have available funds to execute planned activities for the year to December in each calendar year.

This facility will be paid off and retired upon completion of the Norway sale, with the transaction expected to complete in Q3 2015.

Q1 2015 cashflow evolution

Q1-2015 CASHFLOW MOVEMENTS

During the quarter ended March 31, 2015 there was a cash inflow from operating, investing and financing activities of approximately $6.5 million (Q1 2014 outflow of $24 million).

Cashflow from operations

Cash generated from operating activities was $89 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 quarter.

Cashflow from financing activities

Cash generated from financing activities was $17 million primarily due to drawdowns of the debt facilities in Q1 2015 ($26.3 million), less interest and bank charges ($9.6 million).

Cashflow from investing activities

Cash used in investing activities was $60 million, primarily related to further capital expenditure on the GSA development, together with Ythan well costs.

COMMITMENTS

The Company's commitments relate primarily to capital expenditure on the GSA development and Norway licences, in addition to more limited commitments associated with completion of the Ythan field development and the Wytch Farm well workover programme. Rig commitments reflect rig hire costs relating to Norway well commitments and the fifth Stella well. Commitments related to the lease of the BW Athena FPSO have been included within the onerous contracts provision at 31 March 2015. Norway commitments, totalling $41.2 million across both rig and engineering commitments, will transfer on the completion of the disposal of Norway.

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 March 31, 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

During the quarter, the Company accelerated the receipt of the cash benefits of a portion of the accumulated hedging gains.

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 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 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 March 31, 2015 Ithaca had 329,518,620 common shares outstanding along with 23,662,692 options outstanding to employees and directors to acquire common shares. No new options were granted in Q1 2015.

(1) Represents the TSX close price (CAD$0.64) on March 31, 2015. US$:CAD$ 0.79086 on March 31, 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.

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 March 31, 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 March 31, 2015, 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 March 31, 2015, there were no changes in the Company's internal control over financial reporting that occurred during the quarter ended March 31, 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.

"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 March 31, 2015, finance lease assets of $31.9 million and related liabilities of $31.5 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 Q1 2015 was $0.1 million (Q1 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 March 31, 2015 the Company had a loan receivable from FPF-1 Ltd, an associate of the Company, for $58.1 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 dated March 31, 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

The Company believes this risk is mitigated by the financial position of the parties. The joint venture

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.

 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 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 "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, including the acquisition of the Summit Assets and the sale of the Company's Norwegian business expected to complete in Q3 2015;

· 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 and dispositions, including the Summit acquisition and sale of the Company's Norwegian business expected to complete in Q3 2015;

· 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 May 13, 2015. The Q1 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 March 31, 2015 and 2014 and with the Company's audited consolidated financial statements as at December 31, 2014 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.

Consolidated Statement of Income

For the three months ended 31 March 2015 and 2014

(unaudited)

2015

2014

Note

US$'000

US$'000

Revenue

5

70,375

99,640

Operating costs

(28,123)

(41,264)

Oil purchases

-

(418)

Movement in oil and gas inventory

(16,191)

(11,861)

Depletion, depreciation and amortisation

(30,556)

(32,465)

Cost of sales

(74,870)

(86,008)

Gross (Loss)/Profit

(4,495)

13,632

Exploration and evaluation expenses

10

(1,044)

(2,008)

Impairment of assets

-

(2,895)

Administrative expenses

6

(3,584)

(3,699)

Foreign exchange

(1,496)

(373)

Gain on financial instruments

27

29,122

3,962

Gain on farm out

-

2,190

Finance costs

7

(10,122)

(6,274)

Interest income

52

25

Profit Before Tax

8,433

4,560

Taxation

25

(34,511)

11,805

(Loss)/Profit After Tax

(26,078)

16,365

Earnings per share (US$ per share)

Basic

Diluted

24

24

(0.08)

(0.08)

0.05

0.05

The accompanying notes on pages 6 to 24 are an integral part of the financial statements.

Consolidated Statement of Financial Position

(unaudited)

31 March

31 December

Note

2015

US$'000

2014

US$'000

ASSETS

Current assets

Cash and cash equivalents

25,909

19,381

Accounts receivable

8

197,748

266,747

Deposits, prepaid expenses and other

1,597

1,140

Inventory

9

15,662

27,481

Derivative financial instruments

28

102,807

150,760

343,723

465,509

Non-current assets

Long-term receivable

30

58,121

58,338

Long-term Norwegian tax receivable

8

7,032

7,032

Long-term inventory

9

8,126

8,126

Investment in associate

13

18,337

18,337

Exploration and evaluation assets

10

92,908

89,844

Property, plant & equipment

11

1,460,159

1,435,209

Deferred tax assets

105,562

139,266

Goodwill

12

137,114

137,114

1,887,359

1,893,266

Total assets

2,231,082

2,358,775

LIABILITIES AND EQUITY

Current liabilities

Trade and other payables

15

(270,339)

(392,131)

Exploration obligations

16

(4,498)

(5,431)

Onerous contracts

17

(9,897)

(21,635)

(284,734)

(419,197)

Non-current liabilities

Borrowings

14

(812,356)

(784,859)

Decommissioning liabilities

18

(215,343)

(213,105)

Other long term liabilities

19

(91,678)

(92,020)

Contingent consideration

21

(4,000)

(4,000)

Derivative financial instruments

28

(2,919)

(587)

(1,126,296)

(1,094,571)

Net assets

820,052

845,007

Shareholders' equity

Share capital

22

551,632

551,632

Share based payment reserve

23

20,357

19,234

Retained earnings

248,063

274,141

Total equity

820,052

845,007

The financial statements were approved by the Board of Directors on 13 May 2015 and signed on its behalf by:

"Les Thomas"

Director

 "Alec Carstairs"

Director

The accompanying notes on pages 6 to 24 are an integral part of the financial statements.

(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

-

1,693

-

1,693

Options exercised

11,575

(4,525)

 -

7,050

Net income for the period

-

-

 16,365

16,365

Balance, 31 March 2014

547,291

16,422

315,041

878,754

Balance, 1 Jan 2015

551,632

19,234

274,141

845,007

Share based payment

-

1,123

-

1,123

Loss for the period

-

-

(26,078)

(26,078)

Balance, 31 March 2015

551,632

20,357

248,063

820,052

(unaudited)

2015

US$'000

2014

US$'000

Profit Before Tax

8,433

4,560

Adjustments for:

Depletion, depreciation and amortisation

11

30,556

32,464

Exploration and evaluation write off

10

1,044

2,008

Impairment

-

2,895

Onerous contracts

17

(11,391)

-

Share based payment

22

180

429

Loan fee amortisation

7

1,177

926

Revaluation of financial instruments

27

49,556

(2,678)

Gain on farm-out

-

(2,190)

Accretion on decommissioning provisions

2,238

1,305

Bank interest & charges

6,707

3,979

Cashflow from operations

88,500

43,699

(Decrease)/increase in trade and other payables

(39,697)

13,970

Decrease in inventory

16,191

11,861

Decrease in trade and other receivables

2,589

9,572

Tax paid

(1,732)

-

Net cash from operating activities

65,851

79,102

Investing activities

Capital expenditure

(60,246)

(128.705)

Loan to associate

217

(91)

Proceeds on farm-out

-

2,190

Changes in debtors and creditors relating to investing activities

(15,163)

(118,406)

Net cash used in investing activities

(75,192)

(245,012)

Financing activities

Proceeds from issuance of shares

-

7,050

Derivatives

-

(1,315)

Loan draw down

26,280

135,951

Bank interest & charges

(9,579)

(2,917)

Net cash from financing activities

16,701

138,769

Currency translation differences relating to cash & cash equivalents

(832)

2,852

Increase/(decrease) in cash and cash equivalents

6,528

(24,289)

Cash and cash equivalents, beginning of period

19,381

63,435

Cash and cash equivalents, end of period

25,909

39,146

Notes to the consolidated financial statements

1.

NATURE OF OPERATIONS

Ithaca Energy Inc. (the "Corporation" or "Ithaca"), incorporated and domiciled in Alberta, Canada on 27 April 2004, is a publicly traded company involved in the exploration, development and production of oil and gas in the North Sea. The Corporation's registered office is 1600, 333 - 7th Avenue S.W., Calgary, Alberta, Canada, T2P 2Z1. The Corporation's shares trade on the Toronto Stock Exchange in Canada and the London Stock Exchange's Alternative Investment Market in the United Kingdom under the symbol "IAE".

2.

BASIS OF PREPARATION

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

The policies applied in these condensed interim consolidated financial statements are based on IFRS issued and outstanding as of 13 May 2015, the date the Board of Directors approved the statements. Any subsequent changes to IFRS that are given effect in the Corporation's annual consolidated financial statements for the year ending 31 December 2015 could result in restatement of these interim consolidated financial statements.

The consolidated financial statements have been prepared on a going concern basis using the historical cost convention, except for financial instruments which are measured at fair value.

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

The condensed interim consolidated financial statements should be read in conjunction with the Corporation's annual financial statements for the year ended 31 December 2014.

3.

SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS AND ESTIMATION UNCERTAINTY

Basis of measurement

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

Basis of consolidation

The interim consolidated financial statements of the Corporation include the financial statements of Ithaca Energy Inc. and all wholly-owned subsidiaries as listed per note 30. Ithaca has twenty one wholly-owned subsidiaries, four of which were acquired on 31 July 2014 as part of the acquisition of Summit Petroleum Limited ("Summit"). The consolidated financial statements include the Summit group of companies from 31 July 2014 only (being the respective acquisition date). All inter-company transactions and balances have been eliminated on consolidation.

Subsidiaries are all entities, including structured entities, over which the group has control. The group controls an entity when the group is exposed to or has rights to variable returns from its investments with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the group. They are deconsolidated on the date that control ceases.

Business Combinations

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

Goodwill

Capitalisation

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

Impairment

Goodwill is tested annually for impairment and also when circumstances indicate that the carrying value may be at risk of being impaired. Impairment is determined for goodwill by assessing the recoverable amount of each cash generating unit ("CGU") to which the goodwill relates. Where the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognised in the statement of income. Impairment losses relating to goodwill cannot be reversed in future periods.

Interest in joint operations

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

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

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

Revenue

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

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

Foreign currency translation

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

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

Share based payments

The Corporation has a share based payment plan as described in note 25 (c). The expense is recorded in the consolidated statement of income or capitalised for all options granted in the year, with the gross increase recorded in the share based payment reserve. Compensation costs are based on the estimated fair values at the time of the grant and the expense or capitalised amount is recognised over the vesting period of the options. Upon the exercise of the stock options, consideration paid together with the amount previously recognised in share based compensation reserve is recorded as an increase in share capital. In the event that vested options expire unexercised, previously recognised compensation expense associated with such stock options is not reversed. In the event that unvested options are forfeited or expired, previously recognised compensation expense associated with the unvested portion of such stock options is reversed.

Cash and cash equivalents

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

Financial instruments

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

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

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

Analyses of the fair values of financial instruments and further details as to how they are measured are provided in notes 27 to 29.

Inventory

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