Q3-2015 Financial Results

2015 THIRD QUARTER HIGHLIGHTS

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

· Average production for nine months to 30 September 2015 ("YTD 2015") of 12,355 barrels of oil equivalent per day ("boepd"), in line with guidance (YTD 2014: 10,640 boepd)

· YTD 2015 $217 million cashflow from on-going operations1 (YTD 2014: $128 million), including oil price hedging gains, with $57 million of this cashflow generated in Q3 2015

· Adjusted YTD 2015 earnings of $98 million, excluding a non-cash accounting tax charge of $41 million resulting from a reduction in UK tax rates in the first quarter of 2015 (YTD 2014: $25 million)

· YTD 2015 cashflow per share $0.66 (YTD 2014: $0.39) and adjusted YTD 2015 earnings per share $0.30 (YTD 2014: $0.08)

Business resilient to lower oil price environment

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

· Significant commodity price hedging in place - average of 5,900 barrels of oil per day ("bopd") at $64/bbl until June 2017 and approximately 5,000 boepd of gas at 63 pence per therm (~$9.70/MMbtu) until June 2017

· YTD 2015 unit operating expenditure of approximately $33/boe, a reduction of over 40% compared to 2014, and forecast to fall further to around $25/boe following Stella start-up

· Forecast 2015 capital expenditure reduced to $120 million - reflecting $30 million of savings associated with lower Greater Stella Area ("GSA") subsea infrastructure installation costs and removal of Norwegian expenditure

· Solid cash netbacks - underpinned by tax allowances pool of over $1.5 billion at 30 September 2015

Deleveraging process commenced - robust funding headroom ahead of Stella start-up

· Net debt reduced from peak of over $800 million in the first half of 2015 to under $690 million at 31 October 2015 - position expected to be broadly unchanged at year-end 2015

· Deleveraging reflects the benefit of strong operating cashflow generation, lower capital expenditures, the cash received from the sale of the non-core Norwegian business and the recent $66 million equity placing

· Semi-annual redetermination of reserves based lending ("RBL") facilities successfully completed - maintaining over $125 million of funding headroom ahead of Stella start-up

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

· Installation of the GSA central infrastructure and development of the Stella field are at an advanced stage of completion - critical path to first hydrocarbons is completion of the "FPF-1" floating production facility modifications programme

· FPF-1 modifications programme continues to advance towards the planned sail-away of the vessel from the yard in late Q1-2016 - commissioning operations underway

· Agreement entered into with Petrofac providing enhanced incentivisation for the timely delivery of the FPF-1 - further underpinning this key step for the Company

· All the subsea infrastructure that is required to be installed prior to arrival of the FPF-1 on location is now in place following the various offshore campaigns completed during the quarter

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

SUMMARY STATEMENT OF INCOME

(1) Average realised price before hedging

(2) Revenue including stock movements

(3) Q3 2015 Cashflow from On-going Operations of $56.6M less $0.9M onerous contract provision release = total cashflow from operations of $55.7M. Q3 2015 YTD $216.8M less $20.9M to give total cashflow from operations of $196.0M

(4) Based on total cashflow from operations

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

SUMMARY BALANCE SHEET

Notes:

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

The Norwegian Tax Rebate Facility was repaid and retired upon sale of the Norwegian business on 8 July 2015.

CORPORATE STRATEGY

Ithaca Energy Inc. ("Ithaca" or the "Company") is a North Sea oil and gas operator focused on the delivery of lower risk growth through the appraisal and development of UK undeveloped discoveries and the exploitation of its existing UK producing asset portfolio.

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

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

· Maximising cashflow and production from the existing asset base

· Delivering first hydrocarbons from the Ithaca operated Greater Stella Area development

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

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

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

CORPORATE ACTIVITIES

Equity investment completed at 51% premium to 30 day VWAP - providing additional flexibility to execute the financial and strategic priorities of the business

premium equity placing

In October 2015 Ithaca completed a $66 million equity investment in the Company by DKL Investments Limited, a wholly owned subsidiary of Delek Group Ltd. ("Delek"). Delek is an Israeli listed conglomerate with significant natural gas exploration and production activities in the Levant Basin in the Eastern Mediterranean. Following completion of the placing on 20 October 2015, Delek owns 19.9% of the issued and outstanding shares of the Company.

The investment was executed via a non-brokered private placement of 81,865,425 Common Shares in the capital of the Company at CAD$1.05 per share, equivalent to £0.53 per share, representing a 19% premium to the CAD$0.88 per share closing price on the Toronto Stock Exchange ("TSX") on 8 October 2015 (the day prior to announcement of the placing), a 39% premium to the 5 day volume weighted average price ("VWAP") and a 51% premium to the 30 day VWAP.

The investment proceeds have been used to strengthen the balance sheet, reduce bank debt and provide the Company with additional flexibility to pursue value-accretive satellite opportunities in the GSA.

BOARD OF DIRECTORS

As a result of the private placement the Board of Directors has been increased from seven to nine Directors following the appointment of two Non-Executive Director representatives nominated by Delek, Mr Joseph Asaf Bartfeld and Mr Yosef Abu. Mr Bartfeld is the President & Chief Executive Officer of Delek and has held a number of senior positions in the Delek Group including that of Chief Financial Officer over the last 20 years. Mr Bartfeld also serves as Chairman and Director on the Board of Directors of a number of Delek Group subsidiaries and affiliates. Mr Abu is the Chief Executive Officer of Delek Drilling Ltd, a subsidiary of Delek, prior to which he held senior consulting positions in the Israeli Ministries of Finance and Interior.

Planned RBL redetermination review completed - funding headroom of over $125 million maintained

debt facility redetermination

In October 2015 the Company successfully completed its planned semi-annual RBL facilities redetermination review. The Company continues to maintain a solid liquidity position, with over $125 million of funding headroom ahead of planned first hydrocarbons from the GSA at the end of the second quarter of 2016.

Following the RBL redetermination the Company's available bank debt capacity is $515 million prior to Stella start-up, which reflects the lower future oil price assumptions adopted by the banking syndicate during the review. The Company has maintained a robust financial position during this period of lower and more volatile oil prices as a result of the proactive measures taken over the year, ensuring it has the financial flexibility to manage downside risks and pursue potential opportunities within the GSA.

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

SALE oF NORWEGIAN BUSINESS

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

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

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

PRODUCTION & OPERATIONS

Solid uptime achieved across main fields - full year guidance remains unchanged at 12kboe/d

Average production for the first nine months of the year was 12,355 boepd, 94% oil. This represents a 16% increase on the same period in 2014 (YTD 2014: 10,640 boepd), driven largely by the inclusion of additional production from the assets acquired from Sumitomo Corporation (the "Summit Assets") in July 2014 more than out-weighing the reduction associated with the removal of Beatrice Area production following the planned re-transfer of the Beatrice facilities to Talisman in the first quarter of 2015.

Production in Q3 2015 averaged 11,915 boepd, 96% oil, a 10% increase on the same quarter in 2014 (Q3 2014: 10,861 boepd). This increase is predominantly due to the inclusion of volumes from the Pierce and Ythan fields, from which production was re-started / started in December 2014 and May 2015 respectively, offsetting the removal of Beatrice Area volumes and natural decline on a number of fields. The planned maintenance shutdown activities scheduled for the quarter were all efficiently completed, resulting in slightly higher than anticipated production during the quarter.

The producing asset portfolio has continued to perform well over the course of the year, with solid operational uptime achieved across the main fields. Full year 2015 production guidance remains unchanged at 12,000 boepd (95% oil).

As part of the Company's previously announced activities to high grade the producing asset portfolio and remove high cost, marginal assets, production has ceased from the Anglia gas field in the Southern North Sea during the quarter. The planned cessation of production from the Athena field is still anticipated prior to the end of 2015. The total net daily production capacity of the two fields is approximately 1,000 boepd.

GREATER STELLA AREA DEVELOPMENT

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

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

The development involves the creation of a production hub based on deployment of the FPF-1 floating production facility located over the Stella field, with onward export of oil and gas. To maximise initial oil and condensate production and fill the gas processing facilities on the FPF-1, the hub will start-up with five Stella wells. Further wells will then be drilled in the GSA post first hydrocarbons to maintain the gas processing facilities on plateau.

Installation of the GSA central infrastructure and development of the Stella field are at an advanced stage of completion. The key element for delivering first hydrocarbons from the GSA hub is completion of the FPF-1 modifications programme, which is being performed by Petrofac in the Remontowa shipyard in Poland. Completion of the works and sail-away of the vessel from the yard is planned for the end of the first quarter of 2016, with first production from the Stella field anticipated at the end of the second quarter.

FPF-1 commissioning operations in progress

FPF-1 Modification Works

At this stage in the modifications programme the critical path to achieving sail-away of the FPF-1 is the completion of commissioning operations, which commenced during the quarter. Full completion of these operations while the vessel is located in the yard is key to avoiding an extended period of more complicated offshore commissioning activities and delay to the start-up of production.

Continued progress is being made on close out of pre-commissioning activities on the vessel, enabling the various topsides processing, utilities and accommodation sub-systems to be fed into the main commissioning programme. Commissioning of the electrical switchboards that distribute power around the vessel is nearing completion and electrical loop testing on the process control and safety systems is progressing well. Internal vessel inspection activities are advancing, along with commissioning of the various utilities systems. Preparation is also underway for the start-up and commissioning of the power generators in the coming weeks, which represents a key milestone in the on-going work programme.

All subsea infrastructure required to be in place ahead of arrival of the FPF-1 on location is now installed

Subsea Infrastructure WORKS

Following the completion of various offshore campaigns during the quarter, all the subsea infrastructure that is required to be installed prior to the arrival of the FPF-1 on location is now in place. Once the FPF-1 is on location over the Stella field, the only remaining subsea workscope to be performed will be the installation and hook-up of the dynamic risers and umbilicals connecting the infrastructure on the seabed to the FPF-1.

Stella development drilling programme successfully completed in April 2015

Drilling Programme

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

Agreement entered into with Petrofac to provide enhanced incentivisation for the timely delivery of FPF-1 and additional contract cost clarity

FPF-1 modifications contract incentivistion

In September 2015 the Company entered into an agreement with Petrofac in respect of the FPF-1 floating production facility. The agreement provides enhanced incentivisation for the timely delivery of the vessel and also provides important contract cost clarity, thereby ensuring efficient execution of the remaining FPF-1 modification works. The key terms of the agreement are:

· All costs of modifying the FPF-1 above the contract cost cap will continue to be fully paid by Petrofac as incurred;

· Ithaca will pay Petrofac $13.7 million in respect of final payment on variations to the contract, with payment deferred until three and a half years after first production from the Stella field;

· A further payment to Petrofac of up to $34 million will be made by Ithaca dependent on the timing of sail-away of the FPF-1. The maximum payment can be achieved for delivering sail-away of the vessel from the shipyard prior to the end of March 2016, with this incentive payment eroding on a daily basis to zero by 31 July 2016. This payment will also be deferred until three and a half years after first production from the Stella field.

Sales agreement executed with BP for Stella gas production

GAS SALES AGREEMENT

In September 2015 the Company entered into a life of field gas sales agreement with BP Gas Marketing Limited ("BP") for the sale of gas produced from the Stella and Harrier fields. The contract reference price is the UK "NBP" spot price. The agreement includes the ability for Ithaca, at its option, to receive up to £10 million of pre-payments for future gas sales to BP, similar to the arrangements available with Shell Trading International Limited for oil sales.

COMMODITY HEDGING

Significant downside commodity price protection from hedging in place

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

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

· 8,500 bopd hedged at $62/bbl from October 2015 to June 2016

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

Additionally, for gas years 2015-16 the Company has hedges establishing a gas price floor of £0.63/therm (~$9.70/MMbtu) for approximately 200 million therms (~20 billion cubic feet) of production. Given the majority of gas hedging is in the form of put options, the financial benefit of the hedges will be realised regardless of production in the relevant period.

OPERATING EXPENDITURE

Unit operating costs ~$33/boe in Q3 YTD 2015, over 40% lower than in 2014

As part of managing and minimising the impact of the abrupt decline in oil prices since the second half of 2014, the Company has taken a number of important steps to protect the business from a prolonged period of weak oil prices. While a significant degree of cashflow protection is provided by the oil and gas price hedges already in place, the Company and its partners continue to actively work on delivering supply chain cost reductions, operating efficiency improvements and reductions in overheads in order to reset the cost base to reflect the requirements of the current environment.

When combined with the cessation of operations on the high cost Beatrice and Jacky fields and the retransfer of the Beatrice facilities to Talisman in Q1 2015, the 2015 financial results show a step change in unit operating costs compared to the previous year. Specifically, unit operating costs have reduced by over 40% to $33/boe compared to the same period in 2014 (Q3 YTD 2014: $57/boe). This unit operating expenditure reflects inclusion of the costs associated with the Athena and Anglia fields, which were provided for in Q4 2014 as an onerous contract provision. The provision was made and the book value of the fields fully written down in 2014 due to the expectation that 2015 would be the last year of production given costs may well exceed revenues in the current price environment.

Full year unit operating expenditure is anticipated to be in line with the YTD 2015 average of approximately $33/boe, down from the anticipated level at the start of the year of $40/boe and previous forecast guidance of $35/boe.

CAPITAL EXPENDITURE

2015 capital expenditure programme reduced to ~$120M and substantially complete by end Q3 2015

With the majority of the planned 2015 investment programme now completed, it is anticipated that total expenditure for the full year will be around $120 million, being $30 million lower than previously guided. This saving is primarily driven by reduced GSA subsea infrastructure installation costs, resulting from efficient execution of the various offshore campaigns, as well as the removal of expenditure following the sale of the Norwegian business.

Expenditure on the 2016 capital investment programme is currently anticipated to total around $50 million, the majority of which relates to completion of Stella start-up works once the FPF-1 leaves the Remontowa yard in Poland. There are a number of production enhancement opportunities within the existing producing asset portfolio that could be added to the expected capital investment programme should the prevailing economics justify inclusion, with the sanction of any such expenditures within the control of the Company.

NET DEBT

Net debt reduced from a peak of over $800 million to under $690 million as at 31 October 2015

Net debt at 30 September 2015 was $751 million, down from $788 million at the end of the second quarter of 2015, as a result of strong operating cashflow generation, lower capital expenditures and the cash received from sale of the non-core Norwegian business. This net debt position has been further reduced by the $66 million equity investment in the Company that was completed in early October 2015. As a consequence net debt at 31 October 2015 was under $690 million. It is anticipated that net debt at the end of this year will remain broadly unchanged from this level.

LICENCE PORTFOLIO ACTIVITIES

High grading of asset portfolio

As part of routine portfolio review activities, the Company has elected to divest of its 10% working interest in the Scolty / Crathes discoveries to EnQuest plc for a nominal sum and transfer its 20% working interest in licence P1792 that contains the Beverley prospect and Evelyn discovery to Shell UK Limited. Divestment of these licence interests is attributable to the financial and strategic metrics of the potential development opportunities being insufficient to meet Ithaca's investment criteria in a lower Brent price environment. In the end-2014 independent reserves evaluation performed by Sproule International Limited ("Sproule") these licences accounted for approximately four million barrels of net proven and probable reserves.

2015 RESERVES EVALUATION

Preparation for the year-end independent reserves evaluation that will be completed by Sproule International Limited ("Sproule") will commence in the final quarter of the year, with the results expected to be published as usual with the full year 2015 financial results in March 2016. The assessment will reflect Sproule's future oil and gas price assumptions as of 31 December 2015.

Q3 2015 RESULTS OF OPERATIONS

COMMODITY PRICES

The financial results for the three and nine months to 30 September 2015 compared to the corresponding periods in 2014 reflect the impact of the significant fall in Brent prices since the middle of last year. The table above presents the average Brent price for the various periods. The negative impact on revenues of this fall has clearly been mitigated to a significant degree by the oil price hedges the Company had put in place.

REVENUE

THREE MONTHS ENDED 30 SEPTEMBER 2015

Revenue decreased by $48.0 million in Q3 2015 to $42.1 million (Q3 2014: $90.1 million) primarily as a consequence of the $51/bbl or 50% decrease in the pre-hedging realised oil price.

In addition, although produced volumes increased by 10% in Q3 2015 compared to the same quarter in the previous year (refer to the Production & Operations section above), sales volumes recorded in revenues during the period decreased by approximately 7%. The decrease was as a result of Athena and Anglia liftings being accounted for against the onerous contracts provision recorded in Q4 2014 and the build in oil inventory being greater in Q3 2015 as there were no liftings from the Pierce field (refer to the Movement in Inventory section below for more details).

The realised price decrease was however offset to a significant extent by a realised hedging gain of $43 per sales barrel in the quarter, resulting in a $35.0 million gain being reported through Foreign Exchange and Financial Instruments (see below).

If revenues were adjusted to include Athena and Anglia sales volumes, there would be an increase in Q3 2015 sales volumes of 4%.

While the realised oil prices for each of the fields in the Company's portfolio do not strictly follow the Brent price pattern, with some fields sold at a discount or premium to Brent and under contracts with differing timescales for pricing, the average realised price for all the fields trades broadly in line with Brent.

NINE MONTHS ENDED 30 SEPTEMBER 2015

Revenue decreased by $118.1 million in YTD 2015 to $171.6 million (YTD 2014: $289.7 million). This 41% reduction was mainly attributable to the decrease of $49/bbl in the pre-hedging realised oil price, partly mitigated by an 11% increase in sales volumes. The increased sales volumes were largely driven by the inclusion of liftings associated with production from the Summit Assets and start-up of the Ythan field at the end of May 2015, partially offset by the exclusion of Anglia and Athena volumes as noted above.

Significantly the decrease in realised oil price was partially offset by an average realised hedging gain of $29 per sales barrel in the period (excluding the benefit of the accelerated hedging reset of $59.7 million in Q1 2015).

COST OF SALES

THREE MONTHS ENDED 30 SEPTEMBER 2015

Cost of sales decreased in Q3 2015 to $52.0 million (Q3 2014: $103.6 million) as a result of significant reductions in operating costs, depletion, depreciation and amortisation ("DD&A") and movement in oil and gas inventory.

OPERATING EXPENDITURE

Reported operating costs decreased by 63% in the quarter to $25.8 million (Q3 2014: $68.8 million). The main reasons are: i) significant savings realised across the portfolio as a result of supply chain contract cost renegotiations and contractor rate reductions; ii) replacement of high cost Beatrice and Jacky field production with lower cost volumes from the Summit Assets; iii) the absence of the 2013 Sullom Voe Terminal catch-up cost that was charged in 2014; and iv) exclusion of $4.5 million of Athena and Anglia operating costs provided for under an onerous contract provision in Q4 2014.

DD&A

The unit DD&A rate for the quarter decreased significantly to $28/boe (Q3 2014: $38/boe), resulting in the total DD&A expense for the quarter reducing to $30.9 million (Q3 2014: $37.8 million). This reduction was mainly attributable to a different contributing field mix, notably the inclusion of the Summit Assets and the exclusion of the Beatrice and Jacky fields. The blended unit cost has been further reduced by the impairment write downs booked in 2014 as a consequence of the change in oil price environment.

MOVEMENT IN INVENTORY

Oil and gas inventory increased $4.7 million in Q3 2015 (Q3 2014 credit of $3.3 million) mainly due to the timing of liftings on the Pierce field. Movements in oil inventory arise due to differences between barrels produced and sold, with production being recorded as a credit to movement in oil inventory through cost of sales until the oil has been sold.

NINE MONTHS ENDED 30 SEPTEMBER 2015

Cost of sales decreased in YTD 2015 to $185.0 million (YTD 2014: $277.6 million) due to decreases in operating costs and DD&A, partially offset by the movement in oil and gas inventory.

OPERATING EXPENDITURE

Operating costs decreased in the period to $83.4 million (YTD 2014: $162.0 million) as a result of the previously noted high grading of the producing asset portfolio, with increased production from lower operating cost fields, together with the effect of the wider supply chain cost savings achieved across the portfolio and the absence of Athena and Anglia costs provided for under the onerous contract provision.

The unit operating costs for YTD 2015 (inclusive of Athena and Anglia) were $33/boe. This represents a reduction of over 40% compared to the equivalent underlying rate of $57/boe for YTD 2014. It is expected that full year unit operating costs will continue at this reduced level.

DD&A

DD&A for the period decreased to $93.2 million (YTD 2014: $121.6 million). As noted above, this decrease was primarily due to the different contributing field mix along with the impact of the impairment write downs booked in 2014 as a consequence of the change in oil price environment.

MOVEMENT IN INVENTORY

An oil and gas inventory movement of $8.4 million was charged to cost of sales in YTD 2015 (YTD 2014: credit of $7.0 million). As noted in the table below, sales and production volumes over the full YTD 2015 were not significantly different. The charge arises from a reduction in the per barrel valuation of the oil inventory over the nine month period mainly resulting from volumes from the Cook field (which had yet to be lifted at 2014 year end but related to sales priced earlier in 2014 when oil prices were high) having been replaced with volumes from the Pierce field (which are valued at current Brent prices).

IMPAIRMENT CHARGES AND EXPLORATION & EVALUATION EXPENSES

Exploration and evaluation expenses of $0.6 million were recorded in the quarter (Q3 2014: $0.6 million) primarily associated with costs relating to licences deemed non-commercial. There were no impairments in the period, whereas in Q3 2014 the remaining Anglia field value was fully written down.

The YTD 2015 E&E expense primarily relates to the drilling of the unsuccessful Snømus exploration well in Norway in Q2 2015. Given the 1 January 2015 effective date for the divestment of the Norwegian business to MOL, the costs associated with this well were paid for by MOL as part of the transaction completion price adjustments.

ADMINISTRATION EXPENSES

Lower administration expenditure in 2015 driven by on-going cost reduction measures and divestment of Norwegian business

THREE MONTHS ENDED 30 SEPTEMBER 2015

Total administrative expenses decreased in the quarter to $2.7 million (Q3 2014: $3.7 million) due to a number of initiatives to reduce the cost base of the business combined with the removal of overhead costs associated with the Norwegian operations that were sold earlier in the year. Share based payment expenses have remained relatively flat with small fluctuations based on the timing of option grants and therefore the amortisation profile.

NINE MONTHS ENDED 30 SEPTEMBER 2015

Total administrative expenses decreased in the period to $8.2 million (YTD 2014: $11.3 million) due to the reduced cost base of the business and the exclusion of around $2 million (pre-tax) of G&A costs following divestment of the Norwegian business. Given the 1 January 2015 effective date for the divestment of the Norwegian business to MOL, these costs were paid for by MOL as part of the transaction completion price adjustments and as such have been fully reimbursed and will be absent going forward.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

THREE MONTHS ENDED 30 SEPTEMBER 2015

A foreign exchange gain of $2.4 million was recorded in Q3 2015 (Q3 2014: $4.1 million gain). The majority of the Company's revenue is US dollar denominated, while expenditures are predominantly incurred in British pounds (although some US dollar and Euro denominated costs are also incurred). General volatility in the GBP:USD exchange rate is the primary driver behind the foreign exchange gains and losses, with the rate moving from 1.57 at 1 July 2015 to 1.52 at 30 September 2015.

The Company recorded an overall $74.9 million gain on financial instruments for the quarter ended 30 September 2015 (Q3 2014: $39.2 million gain).

$35.8 million of the gain was realised in Q3 2015, comprising a $35.0 million gain on oil hedges maturing during the quarter at an average exercise price of $92/bbl compared to an average Brent price of $50/bbl, combined with a $0.6 million gain on foreign exchange instruments and $0.1 million gain on gas hedges.

Combined with the realised hedging gain was a $39.1 million revaluation of financial instruments as at 30 September 2015, which relates to hedges held at quarter end. This revaluation was primarily due to a positive revaluation of commodity hedges of $41.8 million and a $0.6 million positive revaluation on interest rate swaps, partly offset by a negative revaluation of foreign exchange instruments of $3.3 million. The value of oil hedges at the end of Q3 2015 has increased based on the decrease in the Brent oil forward curve ($53/bbl average to the end of Q2 2017 as at Q3 2015 vs $68/bbl average as at Q2 2015) at the end of the reporting periods. This has been partially offset by the realisation of hedged barrels during the quarter i.e. the transfer of previously unrealised gains to realised gains.

Going forward the Company holds a derivative fair value of $46 million for oil hedges at 30 September 2015 and a $50 million valuation for future gas derivatives.

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

NINE MONTHS ENDED 30 SEPTEMBER 2015

A foreign exchange loss of $1.7 million was recorded in YTD 2015 (YTD 2014: $6.0 million gain) primarily due to volatility in the GBP:USD exchange rate with fluctuation between 1.46 and 1.59 during the period, closing at 1.52 on 30 September 2015.

The Company recorded an overall $94.2 million gain on financial instruments for the nine month period ended 30 September 2015 (Q3 2014: $32.0 million gain).

$145.2 million of the gain was realised in respect of commodity hedges, comprising $59.7 million relating to the accelerated oil hedging gain and $85.5 million relating to oil and gas hedges maturing during the period, with $1.2 million relating to foreign exchange instruments, partly offset by a $0.2 million loss on interest rate swaps.

Offsetting the realised gain was the revaluation of instruments as at 30 September 2015, which relates to instruments still held at quarter end. This $52.1 million revaluation primarily related to a negative revaluation of commodity hedges of $54.5 million, partially offset by a $1.8 million positive revaluation of foreign exchange instruments coupled with a $0.6 million positive revaluation of other instruments. The negative revaluation on commodity instruments was primarily due to the realisation of the amounts noted above (i.e. where they are no longer still held at the period end as they had been realised), partly offset by an increase in value of the remaining hedging instruments based on the movement in the forward curve and the implied volatility at the end of the reporting period.

FINANCE COSTS

THREE MONTHS ENDED 30 SEPTEMBER 2015

Finance costs decreased to $9.5 million in Q3 2015 (Q3 2014: $9.8 million). This decrease is primarily driven by a fall in bank interest and fees, as a result of the decrease in drawn debt (including the senior notes) from $845 million at the end of Q3 2014 to $762 million at the end of Q3 2015.

Accretion costs increased by $0.7 million compared to Q3 2014 due to the recognition of higher decommissioning liabilities as at 30 September 2015 as a result of inclusion of the decommissioning liabilities associated with the Summit Assets.

NINE MONTHS ENDED 30 SEPTEMBER 2015

Finance costs increased to $30.4 million in YTD 2015 (YTD 2014: $21.9 million). This rise primarily reflects increased interest costs and fees incurred in relation to the senior unsecured notes, issued in July 2014, partially offset by the decrease in bank interest and fees noted above.

TAXATION

No UK corporation tax anticipated to be payable prior to 2020

THREE MONTHS ENDED 30 SEPTEMBER 2015

A non-cash tax charge of $12.7 million was recognized in the quarter ended 30 September 2015 (Q3 2014: $0.2 million credit). This charge is lower than the expected tax rate due to credit adjustments primarily relating to the UK Ring Fence Expenditure Supplement and additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac (refer to note 25 in the Q3 2015 Consolidated Financial Statements).

As a result of the above factors, the profit before tax of $55.5 million becomes a profit after tax of $42.8 million (Q3 2014: $8.0 million profit).

NINE MONTHS ENDED 30 SEPTEMBER 2015

A tax credit of $19.5 million was recognised in the nine months ended 30 September 2015 (YTD 2014: $19.8 million credit). This amount includes $63.4 million credit relating to UK and Norway taxation which is a product of the taxable loss generated and adjustments to deferred tax charge primarily relating to the UK Ring Fence Expenditure Supplement, the non-taxable gain on disposal of Norway and additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac (refer to note 25 in the Q3 2015 Consolidated Financial Statements).

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

The UK government announced in its March 2015 budget that the effective rate of corporate income tax on oil and gas companies will be reduced from 62% to 50% with effect from 1 January 2015. The reduction was enacted on 30 March 2015. This resulted in a charge of $52.1 million relating to deferred Corporation Tax. This was partially offset by a credit of $10.6 million relating to the impact in the change of the rate of PRT from 50% to 35% on the deferred PRT liability in the balance sheet.

As a result of the above factors, the profit before tax of $37.1 million becomes a profit after tax of $56.6 million (YTD 2014: $25.0 million profit). Adjusting for the impact of the change in tax rates would give a profit after tax of $98.1 million.

CAPITAL INVESTMENTS

Savings in the year reducing 2015 full year Capital expenditure from $150m to $120m in 2015

Capital additions to development and production ("D&P") assets totalled $130.1 million in YTD 2015. These relate primarily to the execution of the GSA development and the development of the Ythan field.

Capital additions to E&E assets in YTD 2015 were $29.4 million predominantly relating to drilling of the Snømus prospect, the costs of which have been reimbursed upon completion of the sale of the Norwegian operations.

Total capital expenditure in YTD 2015 excluding Norway and capitalised interest was approximately $115 million.

WORKING CAPITAL

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

As at 30 September 2015, the Company had a net working capital balance of $56.1 million, including an unrestricted cash balance of $10.5 million, invested in money market deposit accounts with BNP Paribas. Substantially all of the accounts receivable are current, being defined as less than 90 days. The Company regularly monitors all receivable balances outstanding in excess of 90 days. No credit loss has historically been experienced in the collection of accounts receivable.

Working capital movements are driven by the timing of receipts and payments of balances and fluctuate in any given quarter. A significant proportion of Ithaca's accounts receivable balance is with customers and co-venturers in the oil and gas industry and is subject to normal joint venture/industry credit risks.

Net working capital has decreased over the nine month period to 30 September 2015 mainly as a result of crystallisation of the cash receipt of a proportion of the oil price hedges held at period end offset by increased settlement of payables primarily associated with the on-going GSA development programme. Receivables includes the Company's joint venture partner's share of payables where the Company is the operator hence the reduction as the GSA payables reduce.

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

CAPITAL RESOURCES

Strong liquidity - RBL redetermination completed and funding headroom in excess of $125 million

DEBT FACILITIES

The Company has in place two bank debt facilities, maturing September 2018; a senior RBL facility of up to $575 million and a junior RBL facility of up to $75 million. The availability to draw upon the facilities is reviewed by the bank syndicate on a semi-annual basis, with the results of the October 2015 redetermination resulting in debt availability of $515 million. Both facilities are based on conventional oil and gas industry borrowing base financing terms, neither of which have historic financial covenant tests. The Company also has $300 million senior unsecured notes, due July 2019.

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

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

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

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

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

Following completion of RBL redetermination review in October 2015, the Company continues to maintain funding headroom in excess of $125 million ahead of planned first hydrocarbons from the GSA at the end of the second quarter of 2016.

YTD 2015 CASHFLOW MOVEMENTS

During the nine months ended 30 September 2015 there was a cash outflow from operating, investing and financing activities of approximately $9 million (Q3 YTD 2014 outflow of $4 million).

Cashflow from operations

Cash generated from operating activities was $196 million primarily attributable to cash generated from the Dons, Causeway Area, Cook and Wytch Farm fields, as well as the acceleration of a portion of the accumulated oil hedging gain received during Q1 2015.

Cashflow from financing activities

Cash used in financing activities was $23 million primarily due to interest and bank charges ($27 million YTD 2015).

Cashflow from investing activities

Cash used in investing activities was $126 million, primarily related to further capital expenditure on the GSA development, together with Ythan well costs, partially offset by funds received on the completion of the divestment of the Norwegian business to MOL.

COMMITMENTS

The Company's commitments relate primarily to completion of the capital investment programme on the GSA development, in addition to more limited commitments associated with the Wytch Farm field well workover programme. These commitments will be funded through the Company's existing cash balance, forecast cashflow from operations and available debt facilities.

In addition to the above, the Company will pay Petrofac $13.7 million in respect of final payment on variations to the contract, with payment deferred until three and a half years after first production from the Stella field. A further payment to Petrofac of up to $34 million will be made by Ithaca dependent on the timing of sail-away of the FPF-1. The maximum payment can be achieved for delivering sail-away of the vessel from the shipyard prior to the end of March 2016, with this incentive payment eroding on a daily basis to zero by 31 July 2016. This payment will also be deferred until three and a half years after first production from the Stella field.

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 30 September 2015.

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

COMMODITIES

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

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

FOREIGN EXCHANGE

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

INTEREST RATES

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

QUARTERLY RESULTS SUMMARY

1 Based on weighted average number of shares

The most significant factors to have affected the Company's results during the above quarters, other than transactions such as the Valiant and Summit Asset acquisitions, are fluctuations in underlying commodity prices and movement in production volumes. The Company has utilized forward sales contracts and foreign exchange contracts to take advantage of higher commodity prices while reducing the exposure to price volatility. These contracts can cause volatility in profit after tax as a result of unrealized gains and losses due to movements in the oil price and USD: GBP exchange rate. In addition, the significant reduction in underlying commodity prices resulted in impairment write downs in Q4 2014.

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 30 September 2015 Ithaca had 329,518,620 common shares outstanding along with 21,453,220 options outstanding to employees and directors to acquire common shares.

1. Represents the TSX close price (CAD$0.62) on 30 September 2015. US$:CAD$ 0.75 on 30 September 2015

Following completion of the equity placing on 20 October 2015, the Company has 411,384,045 Common Shares issued and outstanding, with one voting right per Common Share.

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 Energy (UK) Limited

· Ithaca Minerals North Sea Limited

· Ithaca Energy Holdings (UK) Limited

· Ithaca Petroleum Limited

· Ithaca Causeway Limited

· Ithaca Exploration Limited

· Ithaca Alpha (NI) Limited

· Ithaca Gamma Limited

· Ithaca Epsilon Limited

· Ithaca Delta Limited

· Ithaca North Sea Limited

· Ithaca Petroleum Norge AS *

· Ithaca Petroleum Holdings AS

· Ithaca Technology AS

· Ithaca AS

· Ithaca 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 31 July 2014 only (being the acquisition date), the consolidated financial statements of the Summit group of companies. All inter‐company transactions and balances have been eliminated on consolidation. A significant portion of the Company's North Sea oil and gas activities are carried out jointly with others. The consolidated financial statements reflect only the Company's proportionate interest in such activities.

* Following the sale of the Company's Norwegian operations in Q2 2015, Ithaca Petroleum Norge AS has been divested and as of Q3 2015, no longer features in the financial results of the Company.

CRITICAL ACCOUNTING ESTIMATES

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

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

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

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

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

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

All financial instruments are initially recognized at fair value on the balance sheet. The Company's financial instruments consist of cash, restricted cash, accounts receivable, deposits, derivatives, accounts payable, accrued liabilities and the long term liability on the Beatrice acquisition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.

In order to recognize share based payment expense, the Company estimates the fair value of stock options granted using assumptions related to interest rates, expected life of the option, volatility of the underlying security and expected dividend yields. These assumptions may vary over time.

The determination of the Company's income and other tax liabilities / assets requires interpretation of complex laws and regulations. Tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded on the financial statements.

The accrual method of accounting will require management to incorporate certain estimates of revenues, production costs and other costs as at a specific reporting date. In addition, the Company must estimate capital expenditures on capital projects that are in progress or recently completed where actual costs have not been received as of the reporting date.

CONTROL ENVIRONMENT

The Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of the Company's disclosure controls and procedures as at 30 September 2015, and concluded that such disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual filings, interim filings and other reports filed or submitted under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and such information is accumulated and communicated to the Company's management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosures.

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

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

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

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

The Chief Executive Officer and Chief Financial Officer performed an assessment of internal control over financial reporting as at 30 September 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), and concluded that internal control over financial reporting is effective with no material weaknesses identified.

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

As of 30 September 2015, there were no changes in the Company's internal control over financial reporting that occurred during the quarter ended 30 September 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

CHANGES IN ACCOUNTING POLICIES

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

ADDITIONAL INFORMATION

Non-IFRS Measures

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

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

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

Off Balance Sheet Arrangements

The Company has certain lease agreements and rig commitments which were entered into in the normal course of operations, all of which are disclosed under the heading "Commitments", above. Leases are treated as either operating leases or finance leases based on the extent to which risks and rewards incidental to ownership lie with the lessor or the lessee under IAS 17. Where appropriate, finance leases are recorded on the balance sheet. As at 30 September 2015, finance lease assets of $30.5 million and related liabilities of $30.9 million are included on the balance sheet.

Related Party Transactions

A director of the Company is a partner of Burstall Winger Zammit LLP who acts as counsel for the Company. The amount of fees paid to Burstall Winger Zammit LLP in Q3 2015 was $0.0 million (Q3 2014: $0.0 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 30 September 2015 the Company had a loan receivable from FPF-1 Ltd, an associate of the Company, for $58.6 million (31 December 2014: $58.3 million) as a result of the completion of the GSA transactions.

BOE Presentation

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

Well Test Results

Certain well test results disclosed in this MD&A represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery therefrom. Full pressure transient and well test interpretation analyses have not been completed and as such the flow test results contained in this MD&A should be considered preliminary until such analyses have been completed.

RISKS AND UNCERTAINTIES

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

For additional detail regarding the Company's risks and uncertainties, refer to the Company's Annual Information Form for the year ended 31 December 2014, (the "AIF") filed on SEDAR at www.sedar.com.

Commodity Price Volatility

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

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

Foreign Exchange Risk

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

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

Interest Rate Risk

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

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

Debt Facility Risk

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

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

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

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

Financing Risk

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

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

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

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

Third Party Credit Risk

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

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

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

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

Property Risk

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

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

Operational Risk

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

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

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

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

Development Risk

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

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

Competition Risk

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

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

Weather Risk

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

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

Reputation Risk

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

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

FORWARD-LOOKING INFORMATION

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

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

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

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

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

· Capital expenditure programs and other expenditures;

· Anticipated future operating costs;

· 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 and to use currently available capital to manage downside risks and pursue potential opportunities within the core GSA;

· The continued availability of the Facilities;

· The peak net drawn debt requirement prior to Stella start up and expected net debt at year end 2015;

· The timing of the FPF-1 vessel sail-away and Stella first hydrocarbons;

· Expected future amounts and timing of payments associated with the FPF-1 vessel;

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

· The realisation of anticipated benefits from acquisitions and dispositions;

· The planned cessation of production from certain fields;

· The anticipated liabilities associated with third parties' default with respect to joint venture obligations;

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

· Schedules, timing, remaining work requirements and anticipated operational plans for 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;

· Expected future renewal of Authorisations;

· Production rates;

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

· Targeted production levels;

· Expected timing for the completion of the year end reserves evaluation; 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 receipt of necessary regulatory approvals from time to time;

· The Company's development plan for its properties will be implemented as planned;

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

· Reserves volumes assigned to Ithaca's properties;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

· Risks associated with realisation of anticipated benefits of acquisitions and dispositions;

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

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

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

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

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

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

· Adverse regulatory rulings, orders and decisions; and,

· Risks associated with the nature of the common shares.

Additional Reader Advisories

The information in this MD&A is provided as of 13 November 2015. The Q3 2015 results have been compared to the results of the comparative period in 2014. This MD&A should be read in conjunction with the Company's unaudited consolidated financial statements as at 30 September 2015 and 2014 and with the Company's audited consolidated financial statements as at 31 December 2014 together with the accompanying notes and AIF for the year ended 31 December 2014. These documents, and additional information regarding Ithaca, are available electronically from the Company's website (www.ithacaenergy.com) or SEDAR profile at www.sedar.com.

Consolidated Statement of Income

For the three and nine months ended 30 September 2015 and 2014

(unaudited)

Three months ended 30 Sept

Nine months ended 30 Sept

Note

2015

US$'000

2014

US$'000

2015

US$'000

2014

US$'000

Revenue

42,108

90,094

171,635

289,665

5

Operating costs

(25,760)

(68,819)

(83,383)

(161,979)

Oil purchases

-

(270)

-

(1,061)

Movement in oil and gas inventory

4,676

3,312

(8,447)

7,047

Depletion, depreciation and amortisation

(30,946)

(37,809)

(93,205)

(121,580)

Cost of sales

(52,030)

(103,586)

(185,035)

(277,573)

Gross (Loss)/ Profit

(9,922)

(13,492)

(13,400)

12,092

Exploration and evaluation expenses

10

(620)

(612)

(29,720)

(3,067)

Gain on disposal

32

1,034

-

26,271

2,190

Gain on financial instruments

27

74,894

39,229

94,185

31,989

Impairment of assets

-

(7,971)

-

(10,866)

Administrative expenses

6

(2,747)

(3,734)

(8,238)

(11,278)

Foreign exchange

2,354

4,147

(1,656)

5,978

Finance costs

7

(9,464)

(9,844)

(30,360)

(21,865)

Interest income

11

4

62

46

Profit Before Tax

55,540

7,727

37,144

5,219

Taxation

25

(12,728)

227

19,475

19,763

Profit After Tax

42,812

7,954

56,619

24,982

Earnings per share

Basic

24

0.13

0.02

0.17

0.08

Diluted

24

0.13

0.02

0.17

0.08

Consolidated Statement of Financial Position

(unaudited)

30 September

31 December

Note

2015

US$'000

2014

US$'000

ASSETS

Current assets

Cash and cash equivalents

10,454

19,381

Accounts receivable

8

218,175

266,747

Deposits, prepaid expenses and other

3,593

1,140

Inventory

9

18,356

27,481

Derivative financial instruments

28

97,634

150,760

348,212

465,509

Non-current assets

Long-term receivable

30

58,617

58,338

Long-term Norwegian tax receivable

8

 -

7,032

Long-term inventory

9

8,126

8,126

Investment in associate

13

18,337

18,337

Exploration and evaluation assets

10

44,235

89,844

Property, plant & equipment

11

1,471,615

1,435,209

Deferred tax assets

181,146

139,266

Goodwill

12

137,114

137,114

1,919,190

1,893,266

Total assets

2,267,402

2,358,775

LIABILITIES AND EQUITY

Current liabilities

Trade and other payables

15

(292,094)

(392,131)

Exploration obligations

16

(4,164)

(5,431)

Onerous contracts

17

(342)

(21,635)

(296,600)

(419,197)

Non current liabilities

Borrowings

14

(749,839)

(784,859)

Decommissioning liabilities

18

(219,889)

(213,105)

Other long term liabilities

19

(92,014)

(92,020)

Contingent consideration

21

(4,000)

(4,000)

Derivative financial instruments

28

(345)

(587)

(1,066,087)

(1,094,571)

Net Assets

904,715

845,007

Shareholders' equity

Share capital

22

551,632

551,632

Share based payment reserve

23

22,323

19,234

Retained earnings

330,760

274,141

Total equity

904,715

845,007

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

"Les Thomas"

Director

 "Alec Carstairs"

Director

The accompanying notes on pages 6 to 23 are an integral part of the financial statements.

Consolidated Statement of Changes in Equity

(unaudited)

Share Capital

Share Based

Payment

Reserve

Retained Earnings

Total

US$'000

US$'000

US$'000

US$'000

Balance, 1 Jan 2014

535,716

19,254

298,676

853,646

Share based payment

-

4,810

-

4,810

Options exercised

15,916

(6,244)

 -

9,672

Profit for the period

 -

 -

24,982

24,982

Balance, 30 September 2014

551,632

17,820

323,658

 893,110

Balance, 1 Jan 2015

551,632

19,234

274,141

845,007

Share based payment

 -

3,089

 -

3,089

Profit for the period

 -

 -

56,619

56,619

Balance, 30 September 2015

551,632

22,323

330,760

904,715

Consolidated Statement of Cash Flow

For the three and nine months ended 30 September 2015 and 2014

(unaudited)

Three months ended 30 Sept

Nine months ended 30 Sept

2015

US$'000

2014

US$'000

2015

US$'000

2014

US$'000

CASH PROVIDED BY (USED IN):

Operating activities

Profit Before Tax

55,540

7,727

37,144

5,219

Adjustments for:

Depletion, depreciation and amortisation

11

30,946

37,809

93,206

121,580

Exploration and evaluation expenses

 10

620

612

29,721

3,067

Impairment

-

7,971

-

10,866

Onerous contracts

(914)

-

(20,916)

-

Share based payment

238

550

627

1,316

Loan fee amortisation

1,267

1,203

4,324

3,052

Revaluation of financial instruments

27

(39,129)

(38,189)

52,087

(33,495)

Gain on disposal

32

(1,034)

-

(26,271)

(2,190)

Accretion

2,285

1,543

6,784

4,162

Bank interest & charges

5,913

7,099

19,252

14,582

Cashflow from operations

55,732

26,325

195,958

128,159

Changes in inventory, receivables and payables relating to operating activities

(10,353)

11,242

(35,437)

33,390

Petroleum Revenue Tax refunded/(paid)

1,140

-

(3,303)

-

Net cash from operating activities

46,519

37,567

157,218

161,549

Investing activities

Acquisition of Summit

-

(163,541)

-

(163,541)

Capital expenditure

(40,283)

(75,157)

(158,229)

(305,638)

Loan to associate

183

(5,077)

(279)

(25,931)

Proceeds on disposal

32,521

-

32,521

2,190

Changes in receivables and payables relating to investing activities

13,450

(16,787)

(15,843)

(76,758)

Net cash used in investing activities

5,871

(260,562)

(141,830)

(569,678)

Financing activities

Proceeds from issuance of shares

 -

2,106

-

9,673

Decrease in restricted cash

-

12,608

-

12,608

Derivatives

-

(1,050)

-

(2,365)

Loan (repayment)/draw down

(51,500)

(73,139)

3,688

98,726

Senior notes

-

300,000

-

300,000

Bank interest & charges

(15,682)

(8,370)

(26,993)

(18,555)

Net cash from financing activities

(67,182)

232,155

(23,305)

400,087

Currency translation differences relating to cash

(177)

(865)

(1,010)

3,655

Increase / (decrease) in cash and cash equiv.

(14,969)

8,295

(8,927)

(4,387)

Cash and cash equivalents, beginning of period

25,423

50,753

19,381

63,435

Cash and cash equivalents, end of period

10,454

59,048

10,454

59,048

Three months ended 30 Sept

Nine months ended 30 Sept

2015

US$'000

2014

US$'000

2015

US$'000

2014

US$'000

Oil sales

41,380

88,347

167,054