Q3-2014 Financial Results

HIGHLIGHTS THIRD QUARTER 2014

Strong balance sheet and significant hedging provide a solid base in a lower oil price environment

Solid third quarter financial results delivered during the main planned maintenance shutdown quarter of the year

· $43.9 million1 underlying cashflow from operations

· $8.0 million profit after tax

Substantial oil hedging in place, providing significant downside price protection into 2016

· 6,300 barrels of oil per day ("bopd") hedged at average of $102/bbl (70% swaps / 30% puts) from 1 October 2014 until 30 June 2016

· The executed hedges through to mid-2016 result in the Company having a Brent breakeven price for the existing producing asset base of under $20/bbl

Strong fully funded cash position even in lower oil price environment

· $1,010 million debt facilities in place following completion of a five year $300 million senior unsecured notes offering, with a weighted average cost of debt of under 5%

· With inclusion of the assets acquired during the Quarter from Sumitomo Corporation (the "Summit Assets"), the Company has full availability of its $610 million reserve based lending facility

· Net drawn debt of $719 million at the end of Q3-2014 (excluding the Norwegian tax rebate facility)

· Combining a Brent oil price projection of approximately $90/bbl through to the planned start-up of production from the Stella field in mid-2015 with forecast production and operating costs, it is anticipated that peak net drawn debt will be around $815 million

· Given the benefit of the Company's existing oil price hedging and sales agreements, a $75/bbl Brent price sensitivity until mid-2015 increases peak net drawn debt by only a further $15 million

· UK tax allowances pool of $1,306 million at September 30, 2014.

Further production portfolio broadening and enhancement of the Company capital structure during the quarter

· Further broadening of the Company's asset base delivered through completion of the acquisition of three high quality, non-operated UK producing oil field interests from Sumitomo Corporation (the "Summit Assets"). The transaction was completed on 31 July 2014 for a net consideration of $163 million.

· Successful completion of a $300 million, 8.125% coupon, senior unsecured notes offering on 3 July 2014. The notes provide diversification in terms of both funding sources and tenor, complementing the long term production, appraisal and development growth focus of the business. The weighted average cost of all the Company's debt facilities remains under 5%.

Forecast 2014 pro-forma production of ~12.5 kboe/d

· Reflecting the impact of planned summer maintenance shutdowns during the quarter, average pro-forma production in Q3-2014 was approximately 11,600 barrels of oil equivalent per day ("boepd"), 96% oil (including production from the Summit Assets for the entire quarter). Average consolidated production reflecting the contribution from the Summit Assets from the acquisition completion date of 31 July 2014 was 10,861 boepd.

· It is anticipated that full year 2014 pro-forma production will be approximately 12,500 boepd. This equates to consolidated production of approximately 11,200 boepd, reflecting inclusion of production from the Summit Assets from the acquisition completion date.

Further significant Stella field de-risking achieved with completion of fourth development well and 2014 subsea infrastructure installation

· Continued progress has been made during the quarter on execution of the Greater Stella Area development. The fourth Stella development well was successfully completed, further de-risking the initial annualised production forecast for the field of approximately 30,000 boepd (100%), 16,000 boepd net to Ithaca. Operations are currently on-going on the fifth Stella development well, which is scheduled to be completed in early 2015. Work on this year's subsea infrastructure installation campaign has been successfully completed and preparation is well advanced for finishing the remaining subsea activities in early 2015. Construction activities continue on the main deck of the "FPF-1" floating production facility, with completion of the works and the subsequent delivery of first hydrocarbons scheduled for mid-2015.

1. Excludes impact of $12 million Sullom Voe Terminal ("SVT") 2013 reconciliation charge and $5.6 million downwards oil stock revaluation as detailed under Operating Costs section below, both of which are included in the financial statement reported cashflow from operations of $26.3 million.

SUMMARY FINANCIAL STATEMENTS

(1) Average realized price before hedging

(2) Revenue excluding other income

(3) Inventory movement excluding oil stock revaluation

(4) Opex net of forex gains, other income (Nigg cost contribution) and 2013 SVT charge

(5) Underlying cashflow from operations excl. $12m late 2013 SVT charge & oil stock reval. of $5.6m

(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

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

CORPORATE ACTIVITIES

Phased development of Ythan field underway following the licence award in March 2014

Significant proportion of future revenues underpinned through hedges executed at highly favourable prices

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

Issuance of Senior notes introduced additional diversity and rate certainty into the Company's capital structure

YTHAN FIELD DEVELOPMENT

During the quarter the Company obtained approval from the Department of Energy and Climate Change ("DECC") for the Ythan Field Development Plan; Ithaca working interest, 40%, and EnQuest 60% (Operator). The Ythan field, which lies adjacent to the producing Don Southwest ("Don SW") field in which both Ithaca and EnQuest have corresponding working interest levels, is located within the southern area of the Don North East licence that was awarded by the DECC in March 2014.

A phased development of the field is planned, involving an initial production well being drilled from the Don SW field infrastructure. Drilling operations will shortly commence, with the well anticipated to be completed in early 2015. The subsea tie-in of the well to the existing infrastructure is planned for spring 2015, leading to the anticipated start-up of production in the second quarter of 2015. The well is targeting the same Brent reservoir sequence as the Don SW field, in a location where an appraisal well has previously been drilled and tested.

COMMODITY PRICE HEDGING

As part of the overall risk management strategy, the Company's 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 through appropriate commodity price hedging arrangements. The hedging programme is executed at the discretion of the Company, with no minimum commodity price hedging requirements being stipulated by any of the Company's debt finance facilities.

The company has in place the following hedges:

· For the period from 1 October 2014 to 30 June 2016 approximately 6,300 bopd hedged at an average price of $102/bbl (approximately 70% swaps / 30% puts).

· For gas years 2015-16, 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.

SUMMIT ACQUISITION

On 31 July 2014 the Company completed the acquisition of the Summit Assets. The transaction involved the acquisition of interests in three non-operated UK producing oil fields for a net consideration of $163 million. The acquisition further broadens the Company's producing asset base with high quality, long-life oil assets with clear upsides and enables acceleration in the monetisation of existing UK tax allowances. The assets that were acquired were: a further 20% interest in the Cook field in which the Company already had a 41.346% interest; a 7.48% interest in the Pierce field; and, a 7.43% interest in the Wytch Farm field. The acquisition is estimated to increase net proved and probable ("2P") reserves by approximately 12.0 million barrels of oil equivalent (Ithaca management estimate) from the transaction effective date of January 1 2014.

SENIOR NOTES ISSUANCE

On July 3 2014, the Company completed an offering of $300 million 8.125% senior unsecured notes due July 2019, with interest payable semi-annually. The net proceeds of the notes were used to partially repay (without cancelling) the Company's RBL facility, with a portion of it subsequently redrawn to finance the acquisition of the Summit assets on 31 July 2014.

The senior notes have provided important diversity to the sources and tenor of funding within the overall capital structure of the business and have a strong fit with the Company's long term appraisal and development growth focus. The notes also reduce bank funding dependency and provide cost of finance certainty through the fixed rate coupon. The Company seeks to maintain a conservative financial profile and strong balance sheet, with ample liquidity, in order to prudently deliver its planned development activities and continued growth of the business.

NORWEGIAN TAX REBATE FACILITY

On 30 September 2014, the Company executed an amendment to the Norwegian Tax Rebate Facility to increase the facility size from NOK 450 million (~$75 million) to NOK 600 million (~$100 million) and extend its tenure to 31 December 2016. Any drawings under this facility will be fully offset by a receivable of tax refund from the Norwegian government within a maximum of 24 months.

PRODUCTION & OPERATIONS UPDATE

12.5kboe/d 2014 pro-forma production guidance

Average pro-forma production in Q3-2014 was approximately 11,600 barrels of oil equivalent per day ("boepd"), 96% oil, reflecting a full quarter's production from the Summit Assets. Average production including the contribution from the Summit Assets from the acquisition completion date of 31 July 2014 was 10,861 boepd (Q3-2013: 11,942 boepd). Production during the quarter was reduced by planned maintenance shutdowns, most notably with respect to a six week shutdown of the Cook field.

It is anticipated that full year 2014 pro-forma production will be approximately 12,500 boepd. The economic benefit of production from the Summit Assets from the acquisition effective date of 1 January 2014 until completion on 31 July 2014 is offset against the acquisition price, with production post completion being reflected in the Income Statement. As a consequence, the pro-forma production guidance is forecast to correspond to approximately 11,200 boepd being reflected in the full year 2014 Income Statement.

As previously noted, the full year production guidance incorporates the impact of approximately 1,400 boepd of annual average production deferrals primarily associated with an unplanned shut-in of the Causeway Area fields in the second half of this year and the delay in the provision of water injection to the Causeway field by the host platform. The Taqa operated host facility for these fields suffered a platform oil export pump failure that resulted in production from the Causeway Area being shut-in towards the end of Q3-2014. The oil export pump has recently been repaired, so operations on the platform are focused on the required water injection system works. The Company remains on-track to deliver production from the fields in line with the guidance for the year.

With respect to other specific production operations:

· The planned workover to replace the electrical submersible pumps on the "P4" well on the Athena field is nearing completion and it is anticipated that operations to de-mobilise the rig will commence shortly.

· The re-start of production from the Pierce field is expected around the end of the year. Operations are on-going to complete the planned shutdown required to modify and refurbish the floating production, storage and offloading vessel ("FPSO") used on the field to enable the tie-in of a third party field to the FPSO.

GREATER STELLA AREA DEVELOPMENT UPDATE

Fourth Stella development well completed, with strong flow test results further de-risking forecast field production performance

Drilling Programme

The fourth Stella development well, "B2", was completed during the quarter. The well was drilled to a total measured depth subsea of 14,461 feet, with a 2,396 foot gross horizontal reservoir section completed in the Palaeocene Andrew sandstone reservoir. The well intersected high quality sands across a net reservoir interval of 1,658 feet, equating to 69% net pay. As with the previous three Stella development wells, a clean-up flow test was performed on the B2 well in order to effectively remove the drilling fluids used to complete the well. As part of the testing programme the well was flowed at various rates over approximately a 38-hour flowing period in order to obtain additional data and fluid samples from its location on the crest of the structure to assist with reservoir management planning for the field. A maximum flow test was completed during the period, with the well flowing at a rate of 12,005 boepd on a 48/64-inch choke. This rate comprised 5,901 barrels of oil per day and 36.6 million standard cubic feet per day of gas. Fluid samples show that the oil is approximately 47° API.

The programme for the four planned Stella Andrew reservoir development wells has now been completed, with the combined maximum clean-up flow test results achieved by the wells being in excess of 45,000 boepd. This well production capacity significantly de-risks the initial annualised production forecast for the Greater Stella Area hub of approximately 30,000 boepd (100%), 16,000 boepd net to Ithaca.

The ENSCO 100 drilling rig was successfully moved from the B2 well location at the northern drill centre to the main drill centre on the field in early October 2014. Drilling operations are on-going on the fifth well on the field, in the Stella Ekofisk reservoir that underlies the main Stella Andrew reservoir. The Ekofisk well is targeting light oil production in a chalk formation. The characteristics of the formation mean that initial production rates are likely to be lower than those displayed by the wells in the Andrew sandstone reservoir. Completion of the fifth well, which is expected to be in early 2015, will mark the end of the planned Stella development drilling campaign.

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

2014 subsea infrastructure installation programme completed

Subsea Infrastructure WORKS

Work on the 2014 subsea infrastructure installation campaign was successfully completed during the quarter following installation of the FPF-1 mooring spread and backfill operations on the infield flowlines. Preparation is well advanced for finishing the remaining subsea activities in 2015. The main activities to be completed prior to arrival of the FPF-1 on location involve tie-in of the northern drill centre and ongoing Stella Ekofisk wells, installation of the mid-water arch over which the risers and umbilicals connecting the subsea infrastructure to the FPF-1 will be positioned and the approximately 3 kilometre oil export pipeline and associated Single Anchor Loading ("SAL") facilities. The dynamic risers and umbilicals will be installed as part of the FPF-1 hook-up activities once the vessel is on location.

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

FPF-1 modification works focused on completion of plant construction and electrical cable activities

FPF-1 Modification Works

Construction activities continue to advance on the main deck of the FPF-1 floating production facility Pipework, electrical cable and instrumentation installation operations are on-going for the oil and gas processing plant packages. Completion of the accommodation outfitting is progressing well and pre-commissioning activities are underway. Commissioning of the production and control systems will be undertaken on a system by system basis as construction activities are completed in each area of the vessel.

As previously highlighted, the main work programme on the path to first hydrocarbons from the GSA hub is completion of the FPF-1 modification works. First hydrocarbons from the hub remains scheduled for mid-2015 and the Company continues to monitor closely the progress being made on completion of the required works by Petrofac.

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

PORTFOLIO ACTIVITIES

Continued high grading of the producing portfolio

UK

As well as adding high quality assets to the production portfolio such as Pierce, Wytch Farm and Cook, the drive to further enhance the value of the overall portfolio continues with focus on removing high cost, marginal assets. To that end, good progress is being made regarding the previously announced re-transfer of the Beatrice facilities to Talisman at the start of 2015. While production from the Beatrice Area accounts for under 8% of production, it accounts for over 18% of total operating costs. As a result, the Company's opex/boe will reduce by around $3-$4/boe following the re-transfer.

Similar scrutiny has been applied to the non-material Southern North Sea ("SNS") Anglia gas field that is operated by the company, which contributes under 1% to revenue and for which the netbacks continue to tighten through cost pressure from infrastructure providers. It is therefore currently intended that 2015 will be the last year of production from the field and hence the Company has taken a write down of the carrying value of the asset in the quarter.

Continued restructuring of former Valiant Norwegian portfolio completed

28th UK Licensing Round awards

NORWAY

Following restructuring of the Norwegian portfolio transferred as part of the Valiant Petroleum plc ("Valiant") acquisition, which involved exiting the licences in the higher risk Barents Sea and Norwegian Sea via swaps, sales and withdrawals, the Company has established a small, focused Norwegian exploration and appraisal operation centred on lower risk geological and geographic opportunities capable of monetisation prior to development. This focused business is underpinned by the 78% tax refund system operated by the Norwegian government, enabling potentially significant value to be created from limited investment expenditure.

Executing upon the Company's strategy in Norway involves the drilling of approximately two wells per annum with working interests of between 5-25%. To set up the near term well portfolio, the Company has entered into agreements with Dana Petroleum Norway AS and Fortis Petroleum Norway AS to acquire non-operated interests in three anticipated Norwegian North Sea wells. The interests are: with Dana, an 8% interest in Licence PL537 containing the "Myrhauk" prospect, which lies approximately 15 kilometres from the Harald field; and with Fortis, a 10% interest in license PL626 containing the "Rovarkula" prospect, which lies approximately 19 kilometres from the Ivar Aasen platform, currently under development, and a 10% interest in license PL677 containing the "Hyrokkin" prospect, which lies approximately 9 kilometres from the Vilje field, a subsea tieback to the Alvheim field and FPSO facilities. Completion of the transactions are subject to normal regulatory consents.

It is anticipated that two wells will be drilled in 2015 for a total capital expenditure of approximately $10 million net of the Norwegian tax refund payable by the government. The wells will be targeting the Myrhauk (8% working interest) prospect noted above and the SnØmus prospect (25% working interest) that is already in the portfolio.

28th UK licensing round awards

Following the end of the quarter the Company was offered three licences as part of the UK's 28th Offshore Licensing Round: Block 29/10d (Ithaca 54.66% working interest and operator, Dyas 25.34%, Petrofac 20%) in the vicinity of the Company's existing GSA interests; Blocks 211/13c (part) and 211/18c (part) in the vicinity of the Company's Dons Area licences (Ithaca 40% working interest, EnQuest 60%, operator); and, Blocks 22/15a and 23/11d containing the Banks and Esperanza light oil discoveries (Ithaca 100% working interest, operator), which are located close to nearby producing fields such as Everest and Huntingdon. The licence offers are based on the completion of technical studies.

CORPORATE STRATEGY

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

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

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

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

· Maximising cashflow and production from the existing asset base.

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

· Delivering first hydrocarbons from the Ithaca operated GSA development.

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

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

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

Q3 2014 RESULTS OF OPERATIONS

REVENUE

Three months ended September 30, 2014

Revenue decreased by $24.0 million from Q3 2013 to $90.1 million (Q3 2013: $114.1 million). This was primarily driven by reduced oil sales volumes coupled with a decrease in the oil price as a result of a significant decrease in Brent.

Oil sales volumes decreased mainly as a result of lengthy planned maintenance shutdowns resulting in an overall production reduction of 9%. Changes in the timing of liftings from Q3 2013 with lower liftings on the Cook field in Q3 2014 accounted for the remaining difference.

There was a decrease in average realized oil prices of 11% from $113/bbl in Q3 2013 to $101/bbl in Q3 2014. The average Brent price for the quarter ended 30 September 2014 was $101/bbl compared to $110/bbl for Q3 2013. The Company's realized oil prices do not strictly follow the Brent price pattern given the various oil sales contracts in place; with some fields sold at a discount to Brent and some at a premium and also due to differing timescales for pricing. This decrease in realized oil price was partially offset by a realized hedging gain of $0.66/bbl in the quarter. Any further drop in Brent over the coming months will be significantly protected by the oil price hedges the Company has in place averaging $102/bbl.

The decrease in gas sales in Q3 2014 compared to Q3 2013 was primarily due to a reduction in realised gas prices coupled with lower production levels on Topaz as a result of the field being shut in.

Nine Months Ended September 30, 2014

Revenue decreased by $12.5 million in YTD 2014 to $289.7 million (YTD 2013: $302.2 million). This movement is predominantly due to a liftings related reduction in oil sales volumes combined with a modest decrease in realised oil price.

Production volumes in YTD 2014 were 6% higher than in the comparable period in 2013, however oil sales volumes were nevertheless 3% lower primarily due to the timing of liftings, in particular on the Cook field. It should be noted that the lifting related variance is offset by a corresponding movement of inventory through cost of sales.

There was a decrease in average realized oil prices from $107/bbl in YTD 2013 to $106/bbl in YTD 2014. The average Brent price for the nine months ended September 30, 2014 was $106/bbl compared to $109/bbl in YTD 2013. As noted above, the Company's realized oil prices do not strictly follow the Brent price pattern.

Total gas sales decreased largely as a result of lower production volumes in the period due to an extended shut-in of the Topaz field.

COST OF SALES

(1) Restated to reflect adjustments to the provisional values attributed to the business combination accounting for the acquisition of Valiant Petroleum Plc in 2Q 2013.

Three months ended September 30, 2014

Cost of sales, including the Summit assets from 31 July 2014, increased in Q3 2014 to $103.6 million (Q3 2013: $81.2 million) primarily due to increases in operating costs and movement in oil and gas inventory partially offset by a reduction in depletion, depreciation and amortization ("DD&A").

Underlying operating costs increased in the quarter to $56.8million (Q3 2013: $41.9 million) mainly due to the inclusion of the Summit Assets from July 31, 2014. Higher cost share contributions for the use of third party infrastructure (the Sullom Voe Terminal ("SVT") that processes oil from the Company's Northern North Sea assets and the Anasuria FPSO that serves the Cook field) have also contributed to increased operating costs in the quarter.

Additionally, Q3 2014 operating costs include a further $12 million associated with the Sullom Voe Terminal 2013 reconciliation charge previously reported as a contingent liability in Q2 2014 as a result of a late notification from the operator. Following a full audit visit this non-recurring item has been recognised as a cost and settled in Q3 2014. As previously advised, agreements are in place to simplify the method of allocation of SVT costs after 2014 and to base the allocation predominately on oil throughputs, making forecasting more straightforward and reducing the potential significant cost allocation distortions inherent in the current allocation process.

Excluding the impact of the non-recurring SVT prior year charges, Q3 2014 unit operating costs are approximately $57/boe. Underlying unit operating costs, which also brings in other income (Nigg cost contribution) and offsetting forex gains are expected to fall to around $50/boe for the full year. This will result from the increased production from the Causeway Area and the dilution of the concentrated impact of the six week planned shutdown of the Cook field during the quarter.

DD&A charge for the quarter decreased to $37.8 million (Q3 2013: $46.2 million), including $16.2 million related to business combination uplift DD&A. This was primarily due to lower production in the quarter based on the same period in the prior year combined with a different contributing field mix, for example, the inclusion of the Summit Assets and the exclusion of Beatrice and Jacky (previously written down to nil in anticipation of their re-transfer to Talisman). This resulted in the unit DD&A rate for the quarter decreasing to $38/boe (Q3 2013: $42/boe).

As the below "Changes in Accounting Policies" section outlines, the adoption of IFRS and accounting for acquisitions as business combinations has led to general increased DD&A rates.

Of the $37.8 million DD&A charge, $16.2 million - over 40% - arises as a result of fair value accounting associated with business combinations. Approximately 62% of this additional charge is offset through a credit in the deferred tax released through the income statement.

An oil and gas inventory movement of $3.3 million was credited to cost of sales in Q3 2014 (Q3 2013 $6.9 million). This comprised a $8.9m credit as a result of increased stocks arising from the timing of liftings, partially offset by a $5.6 million charge to cost of sales on the revaluation of stock mainly due to the reduction in oil price from $111/bbl at the beginning of the quarter compared to $95/bbl at September 30, 2014.

In Q3 2014 more barrels of oil were produced (957 kbbls) than sold (874 kbbls), mainly as a result of the timing of Cook and Dons field liftings.

* Due to long term inventory transfers and terminal quality adjustments etc.

Nine Months Ended September 30, 2014

Cost of sales increased in YTD 2014 to $277.6 million (YTD 2013: $236.0 million) due to increases in operating costs and DD&A, partially offset by the movement in oil and gas inventory.

Operating costs increased in the period to $162.0 million (YTD 2013: $108.3 million). This was primarily due to the inclusion of costs for the Dons and Causeway Area fields acquired from Valiant (full YTD 2014 compared to only as of April 19, 2013) and the inclusion of Summit Assets as of July 31, 2014 along with the aforementioned impact of the SVT 2013 reconciliation charge and higher cost share contributions for the use of third party infrastructure in 2014. Planned shutdowns in the period on Beatrice and Jacky and some weather related production downtime, particularly in relation to the Cook field during the first quarter of 2014, also contributed to the increase.

DD&A for the period increased to $121.6 million (YTD 2013: $111.9 million). This was primarily due to higher production volumes in YTD 2014 as a result of a full period's contribution from the Dons and Causeway fields as well as the addition of the Summit Assets, offset by no DD&A on the Beatrice and Jacky fields as these assets have been fully written down.

As noted in the three months ended September 30, 2014 the DD&A charge is increased by over 40% as a result of fair value accounting associated with the business combinations.

An oil and gas inventory movement of $7.0 million was credited to cost of sales in YTD 2014 (YTD 2013: charge of $14.8 million). This comprised a $12.2m credit as a result of increased stocks arising from the timings of liftings, partially offset by a $5.2 million charge to cost of sales on the revaluation of stock mainly due to the reduction in oil price from $110/bbl at the beginning of the nine-month period compared to $95/bbl at September 30, 2014.

In YTD 2014 more barrels of oil were produced (2,763 kbbls) than sold (2,660 kbbls), again primarily as a result of the timing of Cook and Dons field liftings.

ADMINISTRATION & EXPLORATION & EVALUATION EXPENSES

Administration costs remain tightly controlled as the Company has grown the asset base

Three Months Ended September 30, 2014

Total administrative expenses increased in the quarter to $3.7 million (Q3 2013: $1.5 million). This was primarily driven by costs related to Norwegian operations of around $1.8 million, approximately half of which is recovered as a cash tax refund from the Norwegian government - the credit is recorded under Taxation. Share based payment expenses increased compared to Q3 2013 due to the expenditure phasing as a result of the timing of option grants coupled with a change in the timewriting profile.

Exploration and evaluation expenses of $0.6 million were recorded in the quarter (Q3 2013: $0.5 million) primarily associated with costs relating to Norwegian licences deemed non-commercial.

Impairment charges in the period reflect the $14.9 million write off ($5.7 million post tax) of Anglia, a Southern North Sea gas field which contributes under 1% of current revenues. As mentioned above this is due to the expectation that 2015 will be the last year of Anglia production given anticipated rising operating costs. This has been partially offset by a $6.9m credit ($3.5 million post tax) on the previously fully written down Jacky field as a result of a downwards revision to the latest Jacky decommissioning estimate.

Nine Months Ended September 30, 2014

Total administrative expenses increased in the period to $11.3 million (YTD 2013: $7.6 million) primarily due to an increase in general and administrative expenses as a result of the associated costs of an enlarged Ithaca group post the Valiant acquisition, particularly including Norway.

The impairment charge represents the aforementioned full write off of the carrying value of Anglia and the Jacky decommissioning provision release combined with the impairment of further costs of a capital nature recognised in the first quarter of 2014 on Beatrice and Jacky, both of which were fully written down at December 31, 2013 in anticipation of the re-transfer of Beatrice to Talisman.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

Three Months Ended September 30, 2014

A foreign exchange gain of $4.1 million was recorded in Q3 2014 (Q3 2013: $2.2 million gain). The majority of the Company's revenue is US dollar driven while expenditures are incurred in British pounds, US dollars and Euros. General volatility in the USD:GBP exchange rate is the primary driver behind the foreign exchange gains and losses, particularly on the revaluation of non US dollar bank accounts and working capital balances (USD:GBP at July 1, 2014: 1.70. USD:GBP at September 30, 2014: 1.62 with fluctuations between 1.61 and 1.72 during the quarter).

The Company recorded an overall $39.2 million gain on financial instruments for the quarter ended September 30, 2014 (Q3 2013: $15.8 million loss). $1.0 million of the gain was realised in the quarter and $38.2million relates to revaluation of future hedging instruments at September 30, 2014. The non-cash revaluation primarily related to a $36.8 million upward revaluation of oil hedges, due to an increase in value of oil swaps and put options based on the decrease in the Brent oil forward curve from the previous quarter end and the implied volatility at the end of the reporting period, coupled with a $1.4 million upwards revaluation of other financial instruments. The $1.0 million cash gain was realised in respect of instruments which expired during the quarter - comprising a $1.1 million realised gain on commodity hedges and a $0.1 million realised loss on interest rate instruments.

The Company does not apply hedge accounting, which can therefore lead to volatility in the results due to the impact of revaluing the financial instruments at each reporting period end. The Brent spot price closed at $95/bbl at September 30, 2014, a decrease from $111/bbl at June 30, 2014, resulting in a mark-to-market gain on commodity hedges that have been entered into to ensure realised prices of over $100/bbl are obtained for those volumes hedged.

Nine Months Ended September 30, 2014

A foreign exchange gain of $6.0 million was recorded in YTD 2014 (YTD 2013: $0.1 million). As highlighted above, general volatility in the USD:GBP exchange rate was the main driver behind the foreign exchange gain in YTD 2014 (USD:GBP at January 1, 2014: 1.65. USD:GBP at September 30, 2014: 1.62 with fluctuations between 1.61 and 1.72 during the period).

The Company recorded a $32.0 million gain on financial instruments for the nine months ended September 30, 2014 (YTD 2013: $5.5 million loss). The main contributor to the gain was the revaluation of instruments at September 30, 2014 which relates to instruments still held at the period end. This $33.1 million non-cash revaluation primarily related to a $33.5 million upward revaluation of oil hedges, a $4.0 million upwards revaluation of gas hedging instruments and a $0.1 million revaluation loss on interest rate swaps, partially offset by a $4.2 million revaluation loss on foreign exchange instruments. A $1.5 million cash loss was realised in respect of instruments which expired during the period - comprising a $5.2 million realised loss on commodity hedges and a $0.3 million realised loss on interest rate instruments, partially offset by a $4.0 million realised gain on foreign exchange instruments.

BUSINESS COMBINATIONS

GOODWILL

As a result of business combination accounting $54.4 million of negative goodwill was recognised in YTD 2013 in relation to the Valiant Acquisition (YTD 2014: Nil). A further $0.9 million of negative goodwill in relation to the Cook acquisition from Noble was recognised in Q1 2013, being a total of $55.3 million of negative goodwill recognised in YTD 2013 (YTD 2014: Nil).

It should be noted that the Summit acquisition resulted in a goodwill asset being recognised in the balance sheet as opposed to a credit to the income statement. The goodwill asset recognised on the acquisition of Summit was as a result of recognising a deferred tax liability as required under IFRS 3 fair value accounting for business combinations. Absent the deferred tax liability the price paid for the Summit assets approximates to the fair value of the assets.

GAIN ON FARM-OUT

In the nine months ended September 30, 2014, a gain of $2.2 million was recognised in the income statement as a result of the farm-out of the Company's cost commitments for and certain rights to the Handcross well, an exploration commitment acquired as part of the Valiant Acquisition. (Q3 2014: Nil and Q3 2013 and YTD 2013: $22.6m relating to the Handcross farm out to Euroil Exploration Limited.)

FINANCE COSTS

Three Months Ended September 30, 2014

Finance costs increased to $9.8 million in Q3 2014 (Q3 2013: $5.0 million). This rise primarily reflects interest and fees incurred in relation to the Company's increased debt financing facilities, and the drawdowns therefrom, including the senior notes completed in Q3 2014.

Nine Months Ended September 30, 2014

Finance costs increased to $21.9 million in YTD 2014 (YTD 2013: $12.2 million). This rise again primarily reflects increased interest and fees incurred in relation to additional drawings under the Company's RBL debt facility combined with interest on the senior notes. Debt drawn in the period has increased from $410 million in Q3 2013 to $776 million in Q3 2014.

The amount drawn under the Norwegian tax rebate facility has also increased from $34 million in Q3 2013 to $69 million in Q3 2014, contributing to the increase in finance costs in the period.

TAXATION

No UK tax anticipated to be payable prior to 2018

Three Months Ended September 30, 2014

A tax credit of $0.2 million was recognized in the quarter ended September 30, 2014 (Q3 2013: $8.2 million credit). A nil charge/credit relating to UK taxation arose due to a combination of the taxable loss generated and adjustments to deferred tax, primarily the UK Ring Fence Expenditure Supplement.

$1.7 million of the credit is due to Norwegian tax refunds, which have been generated as a result of exploration related expenditure, incurred by Ithaca's Norwegian operations during Q3 2014. Norwegian tax refunds totalling $78 million recognised on the balance sheet relate to Norwegian capital expenditure.

The offsetting $1.5 million charge in Q3 2014 relates to Petroleum Revenue Tax ("PRT") of 50% payable on cashflows generated by the Company's Wytch Farm field interest.

As a result of the above factors, profit after tax increased to $8.0 million (Q3 2013: $43.1 million).

No Corporation or Supplementary tax is expected to be payable prior to 2018 relating to upstream oil and gas activities as a result of the $1,306 million of UK tax losses available to the Company.

Nine Months Ended September 30, 2014

A tax credit of $19.8 million was recognised in the nine months ended September 30, 2014 (YTD 2013: $7.5 million charge). $16.9 million of this non-cash credit relates to UK taxation and is a product of the taxable loss generated and adjustments to deferred tax charge primarily relating to the UK Ring Fence Expenditure Supplement and share based payments.

$4.3 million of the credit is due to Norway tax credits which have been generated as a result of exploration expenditure incurred by Ithaca's Norwegian operations.

The offsetting $1.5 million charge relates to PRT of 50% payable on cashflows generated by the Company's Wytch Farm field interest.

As a result of the above factors, profit after tax increased to $25.0 million (YTD 2013: $100.4 million).

CAPITAL INVESTMENTS

Capital expenditure on development and production ("D&P") assets totalled $281 million in YTD 2014, excluding $8 million of decommissioning assets additions, in line with the Company's 2014 full year expectations. This related primarily to development drilling operations on the Stella field, subsea infrastructure installation activities for the GSA hub and the on-going modification works on the FPF-1, along with drilling of the Fionn sidetrack and also the Don Southwest "TJ" well. Additionally, there were a further $246 million of additions relating to the Summit acquisition reflecting the fair value of the acquired PP&E assets.

Capital expenditure on E&E assets in YTD 2014 was $34.8 million, offset by a $7.3 million release of the acquired E&E liability recognised at the time of the Valiant acquisition as well as a $1.4 million transfer from E&E to D&P assets relating to the Don NE (Ythan) development post approval of the Field Development Plan, resulting in a net addition of $26.1 million. Expenditure was primarily focused on the Trell and Lupus exploration wells in Norway where 78% of the cost is subsequently reimbursed by the Norwegian Government resulting in an E&E expenditure net of Norwegian tax refund of $23.7 million.

LIQUIDITY AND CAPITAL RESOURCES

Significant investment in development projects

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

The Company's liquidity requirements arise principally from capital investment and working capital demands. For the periods presented, Ithaca met its liquidity requirements primarily from ongoing cashflow generation from its producing assets and debt financing via drawings on the RBL Facility, the senior notes issued in July 2014 and Norwegian Tax Rebate Facility.

As at September 30, 2014, the Company had a net working capital balance of $9.3 million including a free cash balance of $59.0 million. Available cash has been, and is currently, invested in money market deposit accounts with BNP Paribas. Management has received confirmation from the financial institution that these funds are available on demand.

Cash and cash equivalents decreased in the nine months to September 30, 2014 as a result of investment in the ongoing Stella field development and substantially completing the capital investment programme in the Causeway Area, offset by the issue of the senior notes and net repayment of bank facilities in the nine-month period.

Trade and Other Receivables have increased in the nine months to September 30, 2014 predominantly due to an increase in receivables from partners on GSA related activities. 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 September 30, 2014 substantially all of the accounts receivable is current, being defined as less than 90 days. In the past, the Company has not experienced credit loss in the collection of accounts receivable.

Trade and Other Payables have increased in the nine months to September 30, 2014 due to the cash advances of $36 million under the Shell oil sales agreements partially offset by the unwinding of creditors and accruals in GSA.

At September 30, 2014, the Company had two UK debt facilities available being the $610 million RBL Facility and the $100 million corporate debt facility. At the quarter end, the Company had unused debt facilities totalling approximately $234 million (Q4 2013: $300 million), with approximately $476 million drawn under the RBL Facility. During the quarter the Company successfully completed an offering of $300 million 8.125% senior unsecured notes due July 2019.

The Company also has a Norwegian tax rebate facility of NOK 600 million (~$100 million), under which approximately $69 million was drawn as at September 30, 2014. An amendment to the Norwegian tax rebate facility size was executed during the quarter to increase the facility size from NOK 450 million (~$75 million) to NOK 600 million (~$100 million) and tenure to December 31, 2016.

During the quarter ended September 30, 2014 there was a cash inflow from operating, investing and financing activities of approximately $8.3 million (Q3 2013 $46.7 million).

Cashflow from operations

Cash generated from operating activities was $26.3 million, inclusive of the $12 million late 2013 SVT charge and $5.6 million oil stock revaluation. The principal contributing assets in the period were Dons, Cook and Wytch Farm.

Cashflow from financing activities

Cash generated from financing activities was $232.2 million primarily due to successful completion of the senior notes offering in July 2014.

Cashflow from investing activities

Costs incurred in investing activities were $243.8 million. The main components of capital expenditure related to the acquisition of the Summit Assets ($163.5 million net) combined with drilling of the fourth Stella development well, completion of installation activities on the FPF-1 mooring system, modification works on the FPF-1, and drilling operations on the Don Southwest TJ well. A further $5 million was also advanced to FPF-1 Limited, an associate company, in relation to hull modification costs.

Financing Facilities

The Company remains fully funded, with more than sufficient financial resources to cover anticipated future commitments from its existing cash balance, debt facilities, forecast cashflow from operations and senior notes issued during the quarter. No unusual trends or fluctuations are expected outside the ordinary course of business.

The Company is in compliance with all covenants related to its borrowing facilities. The key covenants on the Reserves Based Lending facility are forward looking in nature calculated using bank defined parameters and assumptions. The three key covenants are:

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

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

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

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

The principal covenants under the undrawn Corporate Facility are:

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

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

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

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

COMMITMENTS

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

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 September 30, 2014.

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

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

From October 1 , 2014 the Company had the following hedging in place:

Oil Hedging

· 4.0 million barrels of oil production over the next 2 years hedged at $102/bbl, 70% swaps / 30% puts ($100/bbl net of put premiums). This hedging underpins approximately $400 million of revenue while retaining oil price upside on a third of the hedged volume.

Gas Hedging

· Approximately 190 million therms (20 Bcf) of gas sales hedged at a floor price of £0.58/therm (~$10/MMBTU) out until gas year 2016. This hedging underpins approximately $190 million of revenue (net of all hedging costs) while retaining upside to rising gas prices beyond £0.63/therm on 100% of the hedged volume.

The Company also enters into interest rate swaps as a measure of hedging its exposure to interest rate risks on the loan facilities. From October 1, 2014, the Company has hedged interest payments on $200 million of debt at 0.44% until 31 December 2015 through interest rate swaps.

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 acquisition, are fluctuations in underlying commodity prices and movement in production volumes. The Company has utilized forward sales contracts and foreign exchange contracts to take advantage of higher commodity prices while reducing the exposure to price volatility. These contracts can cause volatility in profit after tax as a result of unrealized gains and losses due to movements in the oil price and USD: GBP exchange rate.

OUTSTANDING SHARE INFORMATION

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

As at September 30, 2014 and November 11, 2014, Ithaca had 329,518,620 common shares outstanding along with 15,682,164 options outstanding to employees and directors to acquire common shares.

(1) Represents the TSX close price (CAD$2.10) on September 30, 2014. US$:CAD$ 0.8933 on September 30, 2014

CONSOLIDATION

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

The consolidated financial statements include the accounts of Ithaca and its wholly‐owned subsidiaries, listed below, and its associates FPU Services Limited ("FPU") and FPF‐1 Limited ("FPF‐1").

Wholly owned subsidiaries:

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

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

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

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

 Ithaca Petroleum Limited (formerly Valiant Petroleum plc)

 Ithaca Causeway Limited (formerly Valiant Causeway Limited)

 Ithaca Exploration Limited (formerly Valiant Exploration Limited)

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

 Ithaca Gamma Limited (formerly Valiant Gamma Limited)

 Ithaca Epsilon Limited (formerly Valiant Epsilon Limited)

 Ithaca Delta Limited (formerly Valiant Delta Limited)

 Ithaca North Sea Limited (formerly Valiant North Sea Limited)

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

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

 Ithaca Technology AS (formerly Valiant Technology AS)

 Ithaca AS (formerly Querqus AS)

 Ithaca Petroleum EHF (formerly Valiant Petroleum EHF)

 Ithaca SPL Limited (formerly Summit Petroleum Limited)

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

 Ithaca Dorset Limited (formerly Summit Dorset Limited)

 Ithaca Pipeline Limited (formerly Summit Pipeline Limited)

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

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

CRITICAL ACCOUNTING ESTIMATES

Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. These accounting policies are discussed below and are included to aid the reader in assessing the critical accounting policies and practices of the Company and the likelihood of materially different results being reported. Ithaca's management reviews these estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates.

The following assessment of significant accounting policies and associated estimates is not meant to be exhaustive. The Company might realize different results from the application of new accounting standards promulgated, from time to time, by various rule-making bodies.

Capitalized costs relating to the exploration and development of oil and gas reserves, along with estimated future capital expenditures required in order to develop proved and probable reserves are depreciated on a unit-of-production basis, by asset, using estimated proved and probable reserves as adjusted for production.

A review is carried out each reporting date for any indication that the carrying value of the Company's D&P assets may be impaired. For D&P assets where there are such indications, an impairment test is carried out on the Cash Generating Unit ("CGU"). Each CGU is identified in accordance with IAS 36. The Company's CGUs are those assets which generate largely independent cash flows and are normally, but not always, single developments or production areas. The impairment test involves comparing the carrying value with the recoverable value of an asset. The recoverable amount of an asset is determined as the higher of its fair value less costs to sell and value in use, where the value in use is determined from estimated future net cash flows. Any additional depreciation resulting from the impairment testing is charged to the Statement of Income.

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

Recognition of decommissioning liabilities associated with oil and gas wells are determined using estimated costs discounted based on the estimated life of the asset. In periods following recognition, the liability and associated asset are adjusted for any changes in the estimated amount or timing of the settlement of the obligations. The liability is accreted up to the actual expected cash outlay to perform the abandonment and reclamation. The carrying amounts of the associated assets are depleted using the unit of production method, in accordance with the depreciation policy for development and production assets. Actual costs to retire tangible assets are deducted from the liability as incurred.

All financial instruments 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 September 30, 2014, and concluded that such disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual filings, interim filings and other reports filed or submitted under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and such information is accumulated and communicated to the Company's management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosures.

The Chief Executive Officer and Chief Financial Officer have designed, or have caused such internal controls over financial reporting to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of the Company's financial statements for external purposes in accordance with IFRS including those policies and procedures that:

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

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

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

The Chief Executive Officer and Chief Financial Officer performed an assessment of internal control over financial reporting as at September 30, 2014, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), and concluded that internal control over financial reporting is effective with no material weaknesses identified.

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

As of September 30, 2014, there were no changes in the Company's internal control over financial reporting that occurred during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

CHANGES IN ACCOUNTING POLICIES

On January 1, 2011, the Company adopted IFRS using a transition date of January 1, 2010. The financial statements for the period ended September 30, 2014, including required comparative information, have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("IASB").

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

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

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

ADDITIONAL INFORMATION

Non-IFRS Measures

'Cashflow from operations' referred to in this MD&A is not prescribed by IFRS. This non-IFRS financial measure does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. The Company uses this measure to help evaluate its performance. As an indicator of the Company's performance, cashflow from operations should not be considered as an alternative to, or more meaningful than, net cash from operating activities as determined in accordance with IFRS. The Company considers Cashflow from operations to be a key measure as it demonstrates the Company's underlying ability to generate the cash necessary to fund operations and support activities related to its major assets. Cashflow from operations is determined by adding back changes in non-cash operating working capital to cash from operating activities.

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

Off Balance Sheet Arrangements

The Company has certain lease agreements and rig commitments which were entered into in the normal course of operations, all of which are disclosed under the heading "Commitments", above. Leases are treated as either operating leases or finance leases based on the extent to which risks and rewards incidental to ownership lie with the lessor or the lessee under IAS 17. No asset or liability value has been assigned to any leases on the balance sheet as at September 30, 2014.

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 Q3 2014 was $0.0 million (Q3 2013: $0.3 million). These transactions are in the normal course of business and are conducted on normal commercial terms with consideration comparable to those charged by third parties.

As at September 30, 2014 the Company had a loan receivable from FPF-1 Ltd, an associate of the Company, for $57.4 million (December 31, 2013: 31.6 million) as a result of the completion of the GSA transactions.

BOE Presentation

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

Well Test Results

Certain well test results disclosed in this MD&A represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery there from. 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 28, 2014, (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 Company believes that there are no circumstances at present that result in its failure to meet the financial tests and it can therefore draw down upon its Facilities.

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

The Company has established a fully funded business plan and routinely monitors its detailed cashflow forecasts and liquidity requirements to maintain its funding requirements.

The Company believes that there are no circumstances at present that would lead to selected divestment, delays to existing programs

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.

or a default relating to the Facilities.

Third Party Credit Risk

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

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

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

All 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.

Competition Risk

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

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

Weather Risk

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

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

Reputation Risk

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

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

FORWARD-LOOKING INFORMATION

This MD&A and any documents incorporated by reference herein contain certain forward-looking statements and forward-looking information which are based on the Company's internal expectations, estimates, projections, assumptions and beliefs as at the date of such statements or information, including, among other things, assumptions with respect to production, future capital expenditures, future acquisitions and cash flow. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", "scheduled", "targeted", "approximately" and similar expressions are intended to identify forward-looking statements and forward-looking information. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. The Company believes that the expectations reflected in those forward-looking statements and information are reasonable but no assurance can be given that these expectations, or the assumptions underlying these expectations, will prove to be correct and such forward-looking statements and information included in this MD&A and any documents incorporated by reference herein should not be unduly relied upon. Such forward-looking statements and information speak only as of the date of this MD&A and any documents incorporated by reference herein and the Company does not undertake any obligation to publicly update or revise any forward-looking statements or information, except as required by applicable laws.

In particular, this MD&A and any documents incorporated by reference herein, contains specific forward-looking statements and information pertaining to the following:

· The quality of and future net revenues from the Company's reserves;

· Oil, natural gas liquids ("NGLs") and natural gas production levels;

· Commodity prices, foreign currency exchange rates and interest rates;

· Capital expenditure programs and other expenditures;

· The sale, farming in, farming out or development of certain exploration properties using third party resources;

· Supply and demand for oil, NGLs and natural gas;

· The Company's ability to raise capital;

· The continued availability of the Facilities;

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

· The realization of anticipated benefits from acquisitions and dispositions, including the acquisition of the Summit Assets;

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

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

· The Company's future operating and financial results;

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

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

· Production rates;

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

· Targeted production levels; and

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

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

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

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

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

· The Company's development plan for the Stella and Harrier discoveries will be implemented as planned;

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

· Reserves volumes assigned to Ithaca's properties;

· Ability to recover reserves volumes assigned to Ithaca's properties;

· Revenues do not decrease below anticipated levels and operating costs do not increase significantly above anticipated levels;

· Future oil, NGLs and natural gas production levels from Ithaca's properties and the prices obtained from the sales of such production;

· The level of future capital expenditure required to exploit and develop reserves;

· Ithaca's ability to obtain financing on acceptable terms, in particular, the Company's ability to access the Facilities;

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

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

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

The Company's actual results could differ materially from those anticipated in these forward-looking statements and information as a result of assumptions proving inaccurate and of both known and unknown risks, including the risk factors set forth in this MD&A and under the heading "Risk Factors" in the AIF and the documents incorporated by reference herein, and those set forth below:

· Risks associated with the exploration for and development of oil and natural gas reserves in the North Sea;

· Risks associated with offshore development and production including risks of inclement weather and the unavailability of transport facilities;

· Operational risks and liabilities that are not covered by insurance;

· Volatility in market prices for oil, NGLs and natural gas;

· The ability of the Company to fund its substantial capital requirements and operations;

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

· Changes in environmental, health and safety or other legislation applicable to the Company's operations, and the Company's ability to comply with current and future environmental, health and safety and other laws;

· The accuracy of oil and gas reserve estimates and estimated production levels as they are affected by the Company's exploration and development drilling and estimated decline rates;

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

· Risks associated with realisation of anticipated benefits of acquisitions, including the Summit acquisition;

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

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

· The ability of the Company to obtain and maintain all of its required permits and licenses;

· Competition for, among other things, capital, drilling equipment, acquisitions of reserves, undeveloped lands and skilled personnel;

· Changes in general economic, market and business conditions in Canada, North America, the United Kingdom, Europe and worldwide;

· Actions by governmental or regulatory authorities including changes in income tax laws or changes in tax laws, royalty rates and incentive programs relating to the oil and gas industry including any increase in UK or Norwegian taxes;

· Adverse regulatory rulings, orders and decisions; and

· Risks associated with the nature of the common shares.

Additional Reader Advisories

The information in this MD&A is provided as of November 12, 2014. The Q3 2014 results have been compared to the results of the comparative period in 2013. This MD&A should be read in conjunction with the Company's unaudited consolidated financial statements as at September 30, 2014 and 2013 and with the Company's audited consolidated financial statements as at December 31, 2013 together with the accompanying notes and Annual Information Form ("AIF") for the year ended December 31, 2013. Copies of these documents are available without charge from Ithaca or electronically on the internet on Ithaca's SEDAR profile at www.sedar.com.

Consolidated Statement of Income

For the three and nine months ended 30 September 2014 and 2013

(unaudited)

Restated*

Restated*

Three months ended 30 Sept

Nine months ended 30 Sept

Note

2014

US$'000

2013

US$'000

2014

US$'000

2013

US$'000

Revenue

5

90,094

114,112

289,665

302,241

Operating costs

6

(68,819)

(41,893)

(161,979)

(108,275)

Oil purchases

(270)

(34)

(1,061)

(981)

Movement in oil and gas inventory

6

3,312

6,915

7,047

(14,798)

Depletion, depreciation and amortisation

(37,809)

(46,207)

(121,580)

(111,925)

Cost of sales

(103,586)

(81,219)

(277,573)

(235,979)

Gross (Loss)/ Profit

(13,492)

32,893

12,092

66,262

Exploration and evaluation expenses

12

(612)

(509)

(3,067)

(953)

Impairment of assets

(7,971)

-

(10,866)

-

Administrative expenses

(3,734)

(1,518)

(11,278)

(7,596)

Non-recurring Valiant acquisition costs

-

-

-

(10,235)

Total Administrative expenses

7

(3,734)

(1,518)

(11,278)

(17,831)

Operating (Loss)/Profit

(25,809)

30,866

(13,119)

47,478

Foreign exchange

4,147

2,212

5,978

137

Gain/(Loss) on financial instruments

29

39,229

(15,814)

31,989

(5,472)

Release of exploration obligation

19

-

22,649

2,190

22,649

Negative goodwill

-

-

-

55,333

Profit Before Interest and Tax

17,567

39,913

27,038

120,125

Finance costs

8

(9,844)

(4,956)

(21,865)

(12,233)

Interest income

4

3

46

45

Profit Before Tax

7,727

34,960

5,219

107,937

Taxation

27

227

8,183

19,763

(7,492)

Profit After Tax

7,954

43,143

24,982

100,445

Earnings per share

Basic

26

0.02

0.14

0.08

0.34

Diluted

26

0.02

0.13

0.08

0.34

Consolidated Statement of Financial Position

(unaudited)

Note

30 September

2014

US$'000

31 December 2013

US$'000

ASSETS

Current assets

Cash and cash equivalents

59,048

63,435

Restricted cash

9

-

12,198

Accounts receivable

10

355,185

314,727

Deposits, prepaid expenses and other

6,311

21,150

Inventory

11

49,938

21,632

Derivative financial instruments

30

25,198

5,102

495,680

438,244

Non current assets

Long-term receivable

32

57,405

31,655

Long-term inventory

11

8,126

8,126

Investment in associate

16

18,337

18,337

Exploration and evaluation assets

12

80,729

57,628

Property, plant & equipment

13

1,821,513

1,423,712

Goodwill

15

137,114

985

2,123,224

1,540,443

Total assets

2,618,904

1,978,687

LIABILITIES AND EQUITY

Current liabilities

Trade and other payables

18

(486,345)

(472,396)

Exploration obligations

19

(5,593)

(12,859)

(491,938)

(485,255)

Non current liabilities

Borrowings

17

(830,681)

(432,243)

Decommissioning liabilities

20

(222,890)

(172,047)

Other long term liabilities

21

(32,122)

(6,037)

Contingent consideration

23

(4,000)

(4,000)

Derivative financial instruments

30

(199)

(15,550)

Deferred tax liability

27

(143,964)

(9,909)

(1,233,856)

(639,786)

Net Assets

893,110

853,646

Equity attributable equity holders

Share capital

24

(551,632)

535,716

Share based payment reserve

25

(17,820)

19,254

Retained earnings

(323,658)

298,676

Shareholders' Equity

(893,110)

853,646

The financial statements were approved by the Board of Directors on 12 November 2014 and signed on its behalf by:

"Jay Zammit"

Director

 "Les Thomas"

Director

Consolidated Statement of Changes in Equity

(unaudited)

Share Capital

Share based

payment

reserve

Retained Earnings

Total

US$'000

US$'000

US$'000

US$'000

Balance, 1 Jan 2013

431,318

20,340

153,990

605,648

Net income for period

-

-

100,445

100,445

Total comprehensive income

431,318

20,340

254,435

706,093

Shares issued

93,005

-

-

93,005

Share based payment

-

2,917

-

2,917

Options exercised

585

(257)

-

328

Balance, 30 September 2013

524,908

23,000

254,435

802,343

Balance, 1 Jan 2014

535,716

19,254

298,676

853,646

Share based payment

-

4,810

-

4,810

Options exercised

15,916

(6,244)

-

9,672

Net income for the period

-

-

24,982

24,982

Balance, 30 September 2014

551,632

17,820

323,658

893,110

Consolidated Statement of Cash Flow

For the three and nine months ended 30 Sept 2014 and 2013

(unaudited)

Restated*

Restated*

Three months ended 30 Sept

Nine months ended 30 Sept

2014

US$'000

2013

US$'000

2014

US$'000

2013

US$'000

CASH PROVIDED BY (USED IN):

Operating activities

Profit Before Tax

7,727

34,960

(5,219)

107,937

Adjustments for:

Depletion, depreciation and amortisation

37,809

46,206

121,580

111,925

Exploration and evaluation expenses

612

509

3,067

953

Impairment

7,971

-

10,866

-

Share based payment

550

203

1,316

865

Loan fee amortisation

1,203

592

3,052

1,777

Revaluation of financial instruments

(38,189)

13,312

(33,495)

17,074

Movement in goodwill

-

-

-

(55,333)

Gain on disposal

-

-

(2,190)

-

Gain on exploration obligation release

-

(22,321)

-

(22,321)

Accretion

1,543

1,375

4,162

2,965

Bank interest & charges

7,099

2,949

14,582

7,405

Valiant acquisition fees

-

-

-

5,032

Cashflow from operations

26,325

77,785

128,159

178,289

Changes in inventory, receivables and payables relating to operating activities

11,242

(7,925)

33,390

19,950

Net cash from operating activities

37,567

69,860

161,549

198,229

Investing activities

Acquisition of Valiant

-

-

-

(200,636)

Cash acquired on acquisition of Valiant

-

-

-

11,611

Valiant acquisition fees

-

-

-

(5,032)

Acquisition of Cook

-

-

-

(33,370)

Acquisition of Summit

(163,541)

-

(163,541)

-

Capital expenditure

(75,157)

(139,304)

(305,638)

(196,943)

Loan to associate

(5,077)

-

(25,931)

-

Proceeds on disposal

-

-

2,190

-

Changes in receivables and payables relating to investing activities

(16,787)

63,136

(76,758)

(22,133)

Net cash used in investing activities

(260,562)

(76,168)

(569,678)

(446,503)

Financing activities

Proceeds from issuance of shares

2,106

-

9,673

328

(Increase) / decrease in restricted cash

12,608

-

12,608

(3,226)

Derivatives

(1,050)

(3,249)

(2,365)

(12,876)

Loan (repayment)/draw down

(73,139)

58,123

98,726

319,041

Senior notes

300,000

-

300,000

-

Bank interest & charges

(8,370)

(2,816)

(18,555)

(8,321)

Net cash from financing activities

232,155

52,058

400,087

294,946

Currency translation differences relating to cash

(865)

929

3,655

(4,276)

Increase / (decrease) in cash and cash equiv.

8,296

46,679

(4,387)

42,397

Cash and cash equivalents, beginning of period

50,753

27,091

63,435

31,374

Cash and cash equivalents, end of period

59,048

73,770

59,048

73,770

Three months ended 30 Sept

Nine months ended 30 Sept

2014

US$'000

2013

US$'000

2014

US$'000

2013

US$'000

Oil sales

88,347

111,289

282,179

292,506

Gas sales

1,060

2,007

4,579

7,231

Condensate sales

238

56

374

328

Other income

449

760

2,533

2,176

90,094

114,112

289,665

302,241

Three months ended 30 Sept

Nine months ended 30 Sept

2014

US$'000

2013

US$'000

2014

US$'000

2013

US$'000

General & administrative

(3,184)

(1,315)

(9,962)

(6,731)

Non-recurring Valiant acquisition related costs

-

-

-

(10,235)

Share based payment

(550)

(203)

(1,316)

(865)

(3,734)

(1,518)

(11,278)

(17,831)

Three months ended 30 Sept

Nine months ended 30 Sept

2014

US$'000

2013

US$'000

2014

US$'000

2013

US$'000

Accretion

(1,543)

(1,375)

(4,162)

(2,965)

Bank charges

(2,743)

(2,949)

(9,883)

(7,409)

Senior notes interest

(3,862)

-

(3,862)

-

Finance lease interest

(174)

 -

(174)

-

Non-operated asset finance fees

(22)

(40)

(124)

(82)

Prepayment interest

(297)

-

(608)

-

Loan fee amortisation

(1,203)

(592)

(3,052)

(1,777)

(9,844)

(4,956)

(21,865)

(12,233)

30 Sept

2014

US$'000

31 Dec

2013

US$'000

Letters of credit

-