IAE.L Regulatory News (IAE)

2016 HALF YEAR HIGHLIGHTS

Solid cashflow generation during H1-2016

· Average production of 9,378 boepd - ahead of guidance

· Sustained reduction in unit operating costs - full year guidance lowered to $25/boe prior to Stella start-up, down $5/boe or 17%, in line with H1 2016 performance

· $82 million cashflow from operations, driven by reduced operating costs and hedging (cashflow per share $0.20)

· Earnings of $46 million excluding mark-to-market of future commodity hedges, $6 million unadjusted (earnings per share $0.02)

Continued deleveraging of the business ahead of Stella start-up - strong liquidity position

· Net debt reduced from a peak of over $800 million in the first half of 2015 to $606 million at 30 June 2016

· Over $120 million of funding headroom - total debt availability in excess of $730 million following semi-annual RBL redetermination in April 2016

· Significant commodity price protection remains in place - 8,200 boepd hedged from end H1 2016 to mid-2017 at an average price of $59/boe

FPF-1 modifications programme completed

· "FPF-1" floating production facility sail-away commenced early August 2016

· On track for Stella first hydrocarbons in November 2016, three months after sail-away

GSA hub enhanced by future move to oil pipeline exports and expansion of satellite portfolio

· Access secured to major oil export pipeline for future production and initial tie-in works completed, allowing switch from tanker loading to pipeline export during 2017 - reduces fixed operating costs, enhances operational uptime and improves reserves recovery

· Interest in "Vorlich" discovery increased to approximately 33% and a 75% interest and operatorship acquired in the nearby "Austen" discovery

Strong outlook - material near-term step-change in production and cashflow

· Production set to more than double to 20-25,000 boepd and unit operating costs to reduce to under $20/boe with start-up of production from the Stella field

· Attractive set of future investment opportunities within the portfolio - ability to tailor the capital investment programme to the prevailing economic outlook

· Increasing financial flexibility - focus on delivering continued deleveraging of the business within a balanced capital investment programme

SUMMARY STATEMENT OF INCOME

(1) Average realised price before hedging

(2) Revenue net of stock movements

(3) Foreign exchange net of related realised hedging gains & losses

SUMMARY BALANCE SHEET

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

Planned April 2016 RBL redetermination successfully completed - over $120M of headroom in place as at 30 June 2016

DEBT FACILITIES

In April 2016 the Company successfully completed its routine semi-annual reserves based lending ("RBL") facilities review, with in excess of $120 million of funding headroom in place as at 30 June 2016, ahead of first hydrocarbons from the GSA.

The Company completes a semi-annual redetermination process with its RBL bank syndicate, at the end of April and October, to review the borrowing capacity of its assets under the RBLs based on the technical and commodity price assumptions applied by the syndicate. Following the April 2016 redetermination, the Company's available borrowing capacity is over $430 million prior to Stella start-up. When combined with the $300 million senior unsecured notes the Company has in place, the business has a total debt capacity of over $730 million. This compares to net debt at the end of Q2 2016 of $606 million.

The Company is focused on maintaining a solid liquidity position, with substantial deleveraging having already been delivered even before first hydrocarbons from the GSA. Total RBL bank debt has been reduced by almost 40% from a peak of over $500 million in the first half of 2015 to $306 million at the end of Q2 2016. A robust financial position has been retained during the current period of lower and more volatile oil prices as a result of various proactive measures taken to increase the financial strength of the business and ensure that the Company has sufficient flexibility to manage downside risks.

As a consequence of the substantial deleveraging, the Company elected to reduce the size of the debt facilities from $650 million to $535 million, saving approximately $0.5 million in commitment fees, effective June 2016. This change has no effect on the current RBL debt capacity of approximately $430 million, as this is substantially below the reduced facility size of $535 million.

Both RBL facilities are based on conventional oil and gas industry borrowing base financing terms, neither of which have historic financial covenant tests. The Company's $300 million senior unsecured notes, due July 2019, similarly have no historic financial covenant tests.

DIRECTOR & EXECUTIVE CHANGES

Certain director and senior management changes have been made since the start of the year. Following the Company's AGM in June 2016, Jack C. Lee and Frank Wormsbecker retired from the Board of Directors. Brad Hurtubise, a serving Non-Executive Director of the board, succeeded Mr Lee as Non-Executive Chairman. In January 2016 Richard Smith was appointed to the executive team as Chief Commercial Officer, and in April 2016, Nick Muir, Chief Technical Officer, left the company.

PRODUCTION & OPERATIONS

H1 2016 production running ahead of full year guidance

The producing asset portfolio has performed well over H1 2016, with production running ahead of guidance largely as a result of solid performance from the Cook and Dons Area fields. Average production for H1 2016 was 9,378 boepd, 93% oil (H1 2015: 12,578 boepd), which compares to full year base production guidance of approximately 9,000 boepd.

When comparing H1 2016 with the same period in 2015, production has reduced by approximately 25%. This reflects the specific steps taken in 2015 to reposition the portfolio to meet the requirements of the lower Brent price environment, namely the cessation of production from the Athena and Anglia fields, and no significant investment in the existing production portfolio as a consequence of the prevailing uncertainty and volatility in oil prices. Production rates have also been restricted on the Pierce field during H1 2016 due to the requirement to complete remedial works on the field's subsea gas injection flowline.

The majority of the planned 2016 operational programmes on the producing asset portfolio have now been completed, with only the two week Brent System maintenance shutdown that is scheduled for October 2016 remaining; this shutdown will impact production from the Company's Northern North Sea fields. The gas injection flowline works were completed on the Pierce field as planned at the end of Q2 2016 and unrestricted production rates have been restored. Within the Causeway Area a mechanical failure of the second electrical submersible pump in the Causeway well has led to the well being shut-in, with production in the area now coming exclusively from the Fionn field. The impact of this on both current and forecast production is limited given the performance of the other fields in the portfolio.

Full year base production guidance, excluding any contribution associated with start-up of the Stella field during the year, remains unchanged at 9,000 boepd. The additional production contribution during the year resulting from the start-up of Stella will depend on the exact timing of first hydrocarbons from the field. Prompt ramp up of production is anticipated following first hydrocarbons, leading to an expected initial annualised production rate of approximately 16,000 boepd net to Ithaca.

GREATER STELLA AREA DEVELOPMENT

GSA development activities are at an advanced stage of completion - Stella production start-up scheduled for November 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 Ithaca and JV partner owned 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.

FPF-1 modifications programme completed

FPF-1 Modification Works

The FPF-1 modifications programme, which has been undertaken by Petrofac in the Remontowa shipyard in Poland, was completed in July 2016. Importantly, all the onshore scope and testing work scheduled for completion in the yard has been completed as planned avoiding costly carry-over of unfinished work offshore. The vessel has been materially upgraded to accommodate the requirements of the GSA hub. Additional buoyancy and enhancements to the marine systems have been undertaken to extend the operational life of the vessel and entirely new topside oil and gas processing facilities have been installed.

Following the completion of deep water marine system trials, the FPF-1 commenced its tow to the Stella field location in early August 2016. It is anticipated that the period from sail-away to first hydrocarbons is approximately three months. Following the tow the FPF-1 will be moored on location using twelve pre-installed anchor chains. The dynamic risers and umbilicals that connect the subsea infrastructure to the vessel will then be installed. Thereafter, commissioning of the various processing and utility systems that can only be undertaken on location with hydrocarbons from the field will be completed.

Stella development drilling programme successfully completed in 2015

Drilling Programme

The five well Stella development drilling programme was successfully completed in April 2015. The wells have all been successfully cleaned up and suspended in a manner that allows production to commence without the requirement for any further intervention activity once the FPF-1 is on location and hooked up. In total the wells have achieved a combined maximum flow test rate during clean-up operations of over 53,000 boepd (100%). This well capacity significantly de-risks the initial annualised production forecast for the GSA hub of approximately 30,000 boepd (100%), 16,000 boepd net to Ithaca.

Subsea infrastructure ready for arrival of FPF-1

Subsea Infrastructure WORKS

The subsea infrastructure installation campaign associated with start-up of the Stella field was successfully completed in 2015. The only remaining subsea workscope to be undertaken prior to first hydrocarbons relates to the installation and hook-up of the dynamic risers and umbilicals connecting the infrastructure on the seabed to the FPF-1. This activity will be complete once the vessel has been anchored on location.

Access to oil export pipeline secured from 2017, reducing fixed operating costs and increasing the long term value of the GSA

GSA OIL EXPORT PIPELINE

Access to the Norpipe oil pipeline system has been secured for future GSA production, allowing a switch from tanker loading during 2017. This move will significantly reduce the fixed operating costs of the GSA facilities and enhance operational uptime, resulting in improved reserves recovery and increasing the long term value of the GSA as a production hub.

The key work associated with creating a connection to the Norpipe system was successfully executed as part of a fast-track operational programme undertaken during the planned summer 2016 pipeline maintenance shutdown. In addition the Company took advantage of the downturn in industry activity to secure attractive contracting terms, including a lump sum contract for the installation of the 44 kilometre pipeline required from the FPF-1 to the Norpipe system. The net capital expenditure associated with the work programme is approximately $20 million, with the majority being paid in 2017.

Norpipe runs approximately 350 kilometres from the Ekofisk offshore production facilities on the Norwegian Continental Shelf to a dedicated oil processing facility at Teesside in the UK, with various UK fields exporting into the system via a spurline.

LICENCE PORTFOLIO ACTIVITIES

Operatorship obtained of core producing field

Cook Field Operatorship

In March 2016 Ithaca took over operatorship of the Cook field (61.345% working interest) following completion of Shell and ExxonMobil's sale of the Anasuria floating production, storage and offloading vessel (and associated feeder field interests), which serves as the host facility for the field.

Strategic asset acquisitions close to GSA hub -opportunity to leverage infrastructure value

GSA SATELLITE ACQUISITIONs

In line with Ithaca's strategic objective to increase value from the GSA infrastructure through the acquisition of interests in potential satellite fields, the Company entered into four agreements in July 2016 to increase its interest in the Vorlich discovery from approximately 17% to 33% and to acquire a 75% interest and operatorship of the Austen discovery. The Vorlich acquisition increases the Company's net proven and probable reserves by approximately 4MMboe, based on the independent reserves evaluation performed by Sproule International Limited ("Sproule") as of 31 December 2015, with Austen resulting in the addition of contingent resources into the portfolio. The total acquisition cost including potential future contingent payments is under $6 million.

VORLICH

Sale and purchase agreements ("SPA") have been executed with ENGIE E&P UK Limited ("ENGIE E&P"), INEOS UK SNS Limited and Maersk Oil North Sea Limited to acquire 100% of licence P1588 (Block 30/1f), with an effective date of 1 January 2016. Licence P1588 contains approximately 10-20% of the Vorlich discovery, with the balance of the discovery located in licence P363 (Block 30/1c). When taking into account the P363 licence interest acquired from TOTAL E&P UK Limited in January 2016, execution of the three SPAs increases Ithaca's overall interest in the Vorlich discovery by 16% to approximately 33%.

Vorlich was discovered and appraised in 2014 with exploration well 30/1f-13A,Z and 13Z. The well encountered hydrocarbons in a Palaeocene sandstone reservoir in Block 30/1c and a subsequent side-track into Block 30/1f confirmed the westerly extension of the discovery. The well was flow tested at a maximum rate of 5,350 boepd (approximately 80% oil).

Vorlich is located approximately 10 kilometres north of the Company's GSA production hub and was estimated as of 31 December 2015 to contain gross proven and probable undeveloped reserves of approximately 24 Mmboe by Sproule. Following completion of the Vorlich appraisal programme in 2014, current activities are focused on planning and preparation of an FDP.

Upon completion of the three SPAs, the overall Vorlich licence interests will be as follows:

· Licence P363: BP (Operator), 80%; Ithaca, 20%

· Licence PL1588: Ithaca (Operator), 100%

AUSTEN

An SPA was executed with ENGIE E&P to acquire a 75% interest and operatorship of Licence P1823 (Block 30/13b), effective 1 May 2016. The licence contains the Austen discovery, which is located approximately 30 kilometres south-east of the GSA hub.

Austen is an Upper Jurassic oil / gas-condensate accumulation on which a number of wells have been drilled, the most recent being appraisal well 30/1b-10,10Z drilled by ENGIE E&P in 2012 that was flow tested at a maximum rate of 7,820 boepd (approximately 50% oil). The gross contingent resources ("1C" to "3C") associated with Austen are estimated by Ithaca to be in the range of 4-28 MMboe. An independent assessment will be completed at the end of the year as part of the usual annual reserves evaluation exercise.

Upon completion of the acquisition, the Austen licence interests will be: Ithaca (Operator), 75%; Premier Oil, 25%. It is planned for further subsurface and development engineering studies to be completed in order to advance preparation of an FDP for approval prior to January 2019.

Initial considerations are payable at completion of the acquisitions, with additional contingent payments at FDP approval and upon reaching reserves recovery thresholds. The licence acquisitions are expected to complete in the second half of 2016 and are subject to normal regulatory and partner approvals, including approval for the transfer of operatorship. At completion the considerations paid will be subject to normal industry adjustments to reflect costs incurred since the effective dates of the transactions.

West Don Field LICENCE INTEREST

During Q1 2016 First Oil Expro Limited ("First Oil") entered into administration. Consequently, the joint venture partners in the West Don field have exercised their forfeiture rights, resulting in Ithaca acquiring a further 4.125% interest in the West Don field (proportionate to its West Don field interest prior to the First Oil default). Ithaca's total interest in the field is now 21.4%. The Company does not expect any significant cost exposure as a result of First Oil's default other than the associated net incremental decommissioning liability, which is currently estimated to be $1.9 million.

COMMODITY HEDGING

12 months future commodity price protection in place for >90% of production from current producing fields

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

The Company's future commodity hedged position is unchanged from that announced at the previous quarter's financial results. Following the realisation of a $18.8 million gain in Q2 2016, as of 1 July 2016 the Company had 8,200 boepd hedged at an average price of $59/boe for the year to June 2017. This total is comprised of:

· 9,400 boepd (48% oil) at average price of $58/boe for the remaining six months of 2016

· 7,000 boepd (50% oil) at average price of $60/boe in the first six months of 2017.

The above figures include 87 million therms of gas hedging (approximately 9 billion cubic feet), with a price floor of £0.56/therm (~$8.30/MMbtu). The gas hedging is in the form of put options, the financial benefit of which is realised regardless of production in the relevant period.

As at 1 July 2016 the Company's commodity hedges were valued at $46.6 million, $25.6 million for oil hedges and $21.0 million for gas hedges, based on valuations relative to the respective oil and gas forward curves.

OPERATING EXPENDITURE

Forecast full year operating costs for current producing assets reduced to $25/boe

Operating costs in H1 2016 continued on the downward trend established in 2015, with a unit cost of $25/boe being delivered during the period. This represents a substantial 17% saving on the $30/boe level forecast for the existing assets prior to Stella start-up. Cost reductions have been achieved across the portfolio, with the Cook and Wytch Farm fields delivering the most significant savings.

It is expected that the cost savings achieved across the existing producing asset base in H1 2016 can be sustained throughout the year. 2016 unit operating cost guidance prior to Stella start-up is therefore reduced from $30/boe down to $25/boe.

CAPITAL EXPENDITURE

$50 million 2016 capital expenditure programme, ~60% lower than 2015

Total 2016 capital expenditure is anticipated to be approximately $50 million (2015: $117 million), the majority of which relates to the GSA, including activities associated with planning and preparation of a Field Development Plan for the Vorlich discovery. Of this total, $15.2 million was incurred in H1 2016.

Beyond 2016 Ithaca forecast an average underlying capital expenditure of $10-25 million per annum on its producing asset portfolio. This relates to facilities maintenance and low cost production enhancement activities. In addition to this, the Company has a diverse set of further investment opportunities within its existing portfolio and the flexibility to tailor its capital programme to the economic outlook at the time. It is anticipated that the average annual capital expenditure required to develop these opportunities will be between $25 -75 million.

The Company is in the process of developing its capital investment plans for the period following the start-up of production from the Stella field and the 2017 expenditure associated with such activities will be finalised with its joint venture partners later in the year. Planning of the Harrier development well programme is well advanced and work continues on assessing the options for drilling infill wells on the Cook field and the Don NE licence area. The nature of these programmes, being drilling targets that take advantage of existing infrastructure, and the opportunities to secure lower than previously anticipated investment costs mean that these are expected to represent high value targets in the current environment.

DEBT

Further deleveraging in 2016 - net debt reduced to $606M at end Q2 2016

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

Since net debt peaked as anticipated in the first half of 2015 at over $800 million, the Company has significantly delevered the business. Net debt was reduced by a further $60 million in the first half of 2016 to $606 million at 30 June 2016. This reduction reflects the benefit of continuing strong operating cashflow generation from the base producing assets combined with lower capital expenditures across the portfolio.

Deleveraging of the business remains a core priority of the Company, with a step change in the debt reduction profile forecast upon the start-up of Stella production.

TRADING ENVIRONMENT

COMMODITY PRICES

The Q2 2016 financial results reflect the impact of the continued fall in Brent prices that has dominated the sector since the middle of 2014. On a year-on-year basis, the average annual Brent price has decreased by $16/bbl or 26% between Q2 2015 and Q2 2016. When comparing H1 2016 with the same period in 2015, this fall increases to $18/bbl or 31%. While this has had a significant negative impact on revenues, the fall in Brent has been materially mitigated during the period by the significant oil and gas price hedging protection the Company had put in place.

FOREIGN EXCHANGE RATES

The company seeks to minimise currency volatility through active hedging of pounds sterling. Ahead of the introduction of gas sales from the Stella field in the fourth quarter of 2016, the majority of the Company's revenue is US dollar denominated oil sales while approximately 80% of costs are incurred in pounds sterling. The recent sharp fall in GBP vs USD of approximately 10%, following the result of the UK referendum to leave the European Union, is however not expected to have a material net effect on the results of the business in 2016 as a result of the Company's active hedging programme (refer below).

Q2 2016 RESULTS OF OPERATIONS

REVENUE

THREE MONTHS ENDED 30 JUNE 2016

Revenue decreased by $34.7 million in Q2 2016 to $24.5 million (Q2 2015: $59.2 million) as a consequence of a $16/bbl or 26% decrease in the realised oil price prior to taking into account hedging, combined with a 51% reduction in sales volumes. While produced volumes decreased by 23% in Q2 2016 compared to Q2 2015, primarily driven by the cessation of production from the Athena and Anglia fields and natural decline in the Causeway Area, sales volumes decreased more significantly due to lifting schedules. In particular, the drop in sales volumes was attributable to the fact there were no oil liftings from the Cook field in Q2 2016.

The reduction in realised price for the period was offset to a significant extent by realised oil and gas hedging gains of $33 per sales barrel of oil equivalent in the quarter, resulting in an $18.8 million gain being reported through Foreign Exchange and Financial Instruments (see below).

While 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.

SIX MONTHS ENDED 30 JUNE 2016

Revenue decreased by $71.7 million in H1 2016 to $57.8 million (H1 2015: $129.5 million). This 55% reduction was driven by a decrease of $20/bbl or 33% in the pre-hedging realised oil price associated with the fall in Brent during the period, coupled with a 38% decrease in underlying sales volumes.

As noted above, production volumes decreased in H1 2016 primarily due to the cessation of production from the Athena and Anglia fields as well as reduced production on the Cook field and natural decline in

the Causeway Area. Sales volumes were down primarily due to the timing of liftings on the Cook and Pierce fields.

In terms of average realised oil prices, there was a decrease to $40/bbl in H1 2016 from $60/bbl in H1 2015. The average Brent price for the six months ended 30 June 2016 was $40/bbl compared to $58/bbl for H1 2015. As noted above, the Company's realised oil prices do not strictly follow the Brent price pattern. The decrease in realised oil price was partially offset by a realised hedging gain of $38 per sales barrel of oil equivalent in the period.

COST OF SALES

THREE MONTHS ENDED 30 JUNE 2016

Cost of sales decreased in Q2 2016 by approximately 60% to $24.3 million (Q2 2015: $58.1 million). This was attributable to decreases in operating costs, depletion, depreciation and amortisation ("DD&A") and movement in oil and gas inventory.

OPERATING EXPENDITURE

Reported operating costs decreased by 26% in the quarter to $21.8 million (Q2 2015: $29.5 million). Cost reductions were achieved across the portfolio, with the Cook and Wytch Farm fields in particular delivering the most significant savings. This continued focus on driving down costs delivered a unit operating cost of $25/boe for Q2 2016, representing a reduction of 32% compared to the equivalent rate of $37/boe for Q2 2015 and 17% ahead of 2016 guidance levels of $30/boe prior to first oil from the Stella field.

DD&A

The unit DD&A rate for the quarter decreased to $22/boe (Q2 2015: $27/boe), resulting in a total DD&A expense for the period of $19.8 million (Q2 2015: $31.7 million). This reduction in expense was due to a combination of lower production in the quarter compared to the same period in 2015 and impairment write downs booked in Q4 2015 as a result of the change in the oil price environment, which also lowered average DD&A/boe rates.

MOVEMENT IN INVENTORY

An oil and gas inventory movement of $17.3 million was credited to cost of sales in Q2 2016 (Q2 2015: credit of $3.1 million). This credit arose as a result of an underlift in the quarter, predominantly due to the build-up of inventory on the Cook and Pierce fields, combined with an over 30% increase in the valuation of all inventory held due to the increase in oil prices in the quarter.

SIX MONTHS ENDED 30 JUNE 2016

Cost of sales decreased in H1 2016 to $68.4 million (H1 2015: $133.0 million) due to decreases in operating costs, DD&A and the movement in oil and gas inventory.

OPERATING EXPENDITURE

Operating costs decreased in the period to $42.0 million (H1 2015: $57.6 million) primarily as a result of the previously noted effect of cost savings achieved across the portfolio as a consequence of the supply chain cost reduction initiatives.

DD&A

DD&A for the period decreased to $37.4 million (H1 2015: $62.3 million). As noted above, this decrease was primarily due to a combination of lower production and the impact of the write downs booked in 2015 as a consequence of the change in oil price environment.

MOVEMENT IN INVENTORY

An oil and gas inventory movement of $11.0 million was credited to cost of sales in H1 2016 (H1 2015: charge of $13.1 million). In H1 2016 more barrels of oil were produced (1,577 kbbls) than sold (1,391 kbbls), mainly due to the timing of Cook, Dons and Pierce field liftings, resulting in an underlift position and associated build-up in inventory. This inventory build combined with an over 20% increase in valuation of inventory to generate a credit to the income statement.

ADMINISTRATION EXPENSES AND EXPLORATION & EVALUATION EXPENSES

Administration expenses reduced through on-going cost reduction measures

THREE MONTHS ENDED 30 JUNE 2016

ADMINISTRATION EXPENSES

Total administration expenses were reduced by 20% to $1.5 million in Q2 2016 (Q2 2015: $1.9 million). This was largely attributable to the sale of the Norwegian operations in July 2015 as well as a continued focus on cost saving initiatives across the business. Costs incurred in the quarter reflect further reductions in contractor rates and a decrease in both employee and contractor numbers from Q2 2015.

E&E EXPENSES

A minor write off of E&E assets was made at the period end relating to non-commercial prospects. The 2015 comparative reflects the write off of the Snømus well costs drilled as part of the since disposed Norwegian operations.

SIX MONTHS ENDED 30 JUNE 2016

Total administrative expenses decreased in the period to $3.3 million (H1 2015: $5.5 million) primarily due to the cost saving drive initiated as a result of the lower oil price environment as well as the abovementioned absence of Norwegian administrative expenses.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

THREE MONTHS ENDED 30 JUNE 2016

FOREIGN EXCHANGE

While the majority of the Company's revenue is US dollar denominated, expenditures are predominantly incurred in British pounds (some US dollar and Euro denominated costs are also incurred). Consequently, general volatility in the GBP:USD exchange rate is the primary factor underlying foreign exchange gains and losses.

In Q2 2016, a modest foreign exchange gain of $0.4 million was recorded (Q2 2015: $2.5 million loss). This was driven by the GBP:USD exchange rate moving from 1.44 at 1 April 2016 to 1.34 at 30 June 2016 and fluctuations throughout the quarter of between 1.33 and 1.48.

FINANCIAL INSTRUMENTS

The Company recorded an overall loss of $33.5 million on financial instruments for the quarter ended 30 June 2016 (Q2 2015: $9.8 million loss).

An $18.1 million realised gain was made in Q2 2016. This comprised a $9.3 million gain on oil hedges maturing during the quarter (at an average exercise price of $63/bbl compared to an average Brent price of $46/bbl) and a $9.5 million gain on gas hedges (at an average price of 58p/therm compared to an average NBP price of 31p/therm), partially offset by a $0.7 million loss on foreign exchange and interest rate instruments. The total realised gain of $18.1 million in the period was offset by a $51.6 million negative revaluation of instruments as at 30 June 2016. This resulted from a negative revaluation of oil hedges of $23.6 million, gas hedges of $24.0 million and other hedges of $4.0 million. 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.

The $23.6 million negative revaluation of oil hedges was due to a combination of the realisation of hedged oil volumes during the quarter (i.e. the transfer of previously unrealised gains to realised gains), coupled with a decrease in the value of the remaining oil hedges at the end of Q2 2016 as a result of an increase in the oil price forward curve from 31 March 2016 to 30 June 2016. The $24.0 million negative revaluation of gas hedges arises in the same way, being a combination of realisations during the quarter and a negative revaluation of the remaining gas hedges at the end of Q2 2016 due to an increase in the gas forward curve in the three months to 30 June 2016.

SIX MONTHS ENDED 30 JUNE 2016

FOREIGN EXCHANGE

A modest foreign exchange gain of $0.9 million was recorded in H1 2016 (H1 2015: $4.0 million loss) primarily due to volatility in the GBP:USD exchange rate, with fluctuations between 1.33 and 1.48 during the period and a closing rate of 1.34 on 30 June 2016.

FINANCIAL INSTRUMENTS

The Company recorded an overall $28.3 million loss on financial instruments for the six month period ended 30 June 2016 (H1 2015: $19.0 million gain).

A $58.0 million gain was recorded in respect of realised commodity hedges, comprising $32.1 million on oil hedges and $25.9 million on gas hedges maturing during the period.

Offsetting the realised gain was the revaluation of instruments as at 30 June 2016, which values instruments still held at quarter end. This $85.2 million revaluation related to a negative revaluation of oil hedges of $43.1 million, a negative revaluation of gas hedges of $36.9 million and a negative revaluation of foreign exchange and interest rate instruments of $5.2 million. The loss on commodity instruments was primarily due to the realisation of the amounts noted above (i.e. where they are no longer still held at the period end), combined with a decrease in value of the remaining swaps based on the movement in the forward curve from the start of the year to the end of the reporting period.

As of 1 July 2016, the Company's commodity hedges were valued at $46.6 million, $25.6 million for oil hedges and $21.0 million for gas hedges, based on valuations relative to the respective oil and gas forward curves. This asset is partly offset by a liability relating to the value of foreign exchange and interest rate hedging instruments held at the period end of $5.3 million.

FINANCE COSTS

Reducing finance cost profile driven by decreasing net debt

THREE MONTHS ENDED 30 JUNE 2016

Finance costs decreased to $9.3 million in Q2 2016 (Q2 2015: $10.8 million). This reduction is primarily attributable to the decrease in RBL bank interest resulting from the significant deleveraging of the business over the last twelve months, with drawn bank debt having fallen from $513 million at 30 June 2015 to $332 million at 30 June 2016. All other finance costs have remained relatively stable quarter on quarter.

SIX MONTHS ENDED 30 JUNE 2016

Finance costs decreased to $18.5 million in H1 2016 (H1 2015: $20.9 million). As noted above, this reduction primarily reflects lower RBL interest costs as a result of the reduced drawn debt.

TAXATION

No UK tax anticipated to be payable prior to 2020

THREE MONTHS ENDED 30 JUNE 2016

A tax credit of $32.6 million was recognised in the three months ended 30 June 2016 (Q2 2015: $66.7 million credit). Significant components of the $32.6 million Corporation Tax ("CT") credit include a $15.2 million credit relating to the UK Ring Fence Expenditure Supplement and $8.1 million in respect of additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac (refer to note 24 in the Q2 2016 Consolidated Financial Statements).

The Q2 2015 UK and Norway credit included adjustments to the tax charge relating to the UK Ring Fence Expenditure Supplement and additional Stella related capital allowances as above and also incorporated the non-taxable gain on disposal of Norway.

As a result of the above factors, the Q2 2016 loss before tax of $44.1 million becomes a loss after tax of $11.5 million (Q2 2015: $39.9 million loss).

SIX MONTHS ENDED 30 JUNE 2016

A tax credit of $66.8 million was recognised in the six months ended 30 June 2016 (H1 2015: $32.2 million credit). Significant components of the $42.7 million Corporation Tax ("CT") credit include a $29.4 million credit relating to the UK Ring Fence Expenditure Supplement and $11.7 million in respect of additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac (refer to note 24 in the Q2 2016 Consolidated Financial Statements), offset by the impact of the removal of PRT on CT of $11.1 million.

It was announced in the UK Budget on 16 March 2016 that Petroleum Revenue Tax ("PRT") was effectively abolished from 1 January 2016 with the introduction of a 0% rate. This eliminated the Company's future PRT tax charge from 1 January 2016. The PRT rate change has been enacted and therefore the deferred PRT provision was fully released through the Q1 2016 results giving rise to a credit of $24.2 million in H1 2016.

Further, it was also announced in the UK Budget that the Supplementary Charge in respect of ring fence trades ("SCT") will be reduced from 20% to 10% with effect from 1 January 2016. This will reduce the Company's future SCT charge accordingly. The impact of the 10% reduction in the Supplementary Charge will reduce the net deferred tax assets by approximately $87 million and is expected to impact the financial statements in the second half of 2016 when the rate change is enacted.

Note that the H1 2015 comparative contains a charge of $41.5 million relating to the previous changes in the Supplementary charge and PRT rates enacted in Q1 2015.

CAPITAL INVESTMENTS

2016 capital investment programme primarily focused on GSA development activities

Capital additions in H1 2016 totalled $29.1 million, with the major component being development and production ("D&P") assets. Excluding capitalised interest costs and non-cash additions relating to decommissioning, capital expenditure was approximately $15.2 million. This mainly related to activities on the GSA.

WORKING CAPITAL

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

As at 30 June 2016 Ithaca had a net working capital balance of $36.4 million, including an unrestricted cash balance of $25.9 million held with BNP Paribas. Substantially all of the accounts receivable are current, being defined as less than 90 days. The Company regularly monitors all receivable balances outstanding in excess of 90 days. No credit loss has historically been experienced in the collection of accounts receivable.

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

Net working capital has decreased over the six month period to 30 June 2016 mainly as a result of a reduction in the commodity hedging instrument asset values of $86 million noted above, offset by a build in inventory.

CAPITAL RESOURCES

Over $120 million funding headroom with net debt reduced to $606 million at end Q2 2016

DEBT FACILITIES

As at 30 June 2016, the Company has debt facilities totalling $535 million ($475 million senior RBL Facility and $60 million junior RBL), following the voluntary reduction in the facilities size from a total of $650 million (see "Corporate Activities" above). The Company has funding headroom of over $120 million following the completion of the April 2016 RBL redetermination process where bank debt capacity was set at over $430 million. The facilities are both due September 2018. The Company also has $300 million senior unsecured notes, due July 2019.

The Company's debt facilities are expected to be sufficient to ensure that adequate financial resources are available to cover anticipated future commitments when combined with existing cash balances and forecast cashflow from operations. As noted above, the bank debt facilities are subject to semi-annual redeterminations of available debt capacity using forward looking assumptions, of which future oil and gas prices are a key component. Movements in forecast commodity prices can therefore have a significant impact on available debt capacity and limit the Company's ability to borrow.

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.

Further cash inflow and reduction in net debt delivered in H1 2016

H1 2016 CASHFLOW MOVEMENTS

During the six months ended 30 June 2016 there was a cash inflow from operating, investing and financing activities of approximately $14.3 million (H1 2015 inflow of $6.0 million).

Cashflow from operations

Cash generated from operating activities was $81.6 million. Revenues from the producing asset portfolio were bolstered by the substantial hedging programme in place, while operating costs reduced by almost 30% period on period.

Cashflow from financing activities

Cash used in financing activities was $46.1 million, being primarily repayments of the debt facilities during the period.

Cashflow from investing activities

Cash used in investing activities was $27.3 million, primarily associated with further capital expenditure on the GSA development (including capitalised interest).

COMMITMENTS

The Company's commitments relate primarily to completion of the capital investment programme on the GSA development, along with other on-going operational commitments across the portfolio. Given the highly advanced status of the GSA development, these commitments are relatively modest and are forecast to be funded from the operating cashflows of the business.

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 June 2016.

COMMODITIES

The following table summarises the commodity hedges in place at 30 June 2016.

FOREIGN EXCHANGE

The Company enters into forward contracts as a means of hedging its exposure to foreign exchange rate risks. As at the end of the quarter, the Company had the following hedged position:

INTEREST RATES

The Company enters into interest rate swaps as a means of hedging its exposure to interest rate risks on the loan facilities. As at the end of the quarter, the Company had hedged interest payments on $50 million of drawn debt at 1.24% for the period to December 2016.

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 are fluctuations in underlying commodity prices and movement in production volumes. The Company has utilised hedging and foreign exchange contracts to take advantage of higher commodity prices and beneficial exchange rates and reduce its exposure to volatility associated with these key factors. However, these contracts can cause volatility in profit after tax as a result of unrealised gains and losses due to movements in the oil price and GBP:USD exchange rate. In addition, the significant reduction in underlying commodity prices over the period has resulted in impairment write downs in Q4 2014 and Q4 2015.

OUTSTANDING SHARE INFORMATION

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

As at 30 June 2016 Ithaca had 411,784,045 common shares outstanding along with 28,746,470 options outstanding to employees and directors to acquire common shares.

(1) Represents the TSX close price (CAD$1.25) on 30 June 2016. US$:CAD$ 0.77 on 30 June2016

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

· Ithaca SP UK Limited

· Ithaca Dorset Limited

· Ithaca Pipeline Limited

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 and E&E assets may be impaired. For 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 recognised 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 recognised at fair value on the balance sheet. The Company's financial instruments consist of cash, accounts receivable, deposits, derivatives, accounts payable, accrued liabilities, contingent consideration and borrowings. Measurement in subsequent periods is dependent on the classification of the respective financial instrument.

In order to recognise 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 June 2016, 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, summarised 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 authorisations of management and directors of the Company; and

(c) are designed to provide reasonable assurance regarding prevention or timely detection of unauthorised 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 June 2016, 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 June 2016, there were no changes in the Company's internal control over financial reporting that occurred during the quarter ended 30 June 2016 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 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 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 standardised 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.

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 June 2016, finance lease assets of $29.6 million and related liabilities of $29.9 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 Q2 2016 was $0.0 million (Q2 2015: $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 June 2016 the Company had loans receivable from FPF-1 Limited and FPU Services Limited, associates of the Company, for $60.2 million and $0.1 million, respectively (30 June 2015: $58.8 million and $0.2 million, respectively) 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, utilising a conversion ratio at 6 mcf: 1 bbl may be misleading as an indication of value.

Reserves & Resources

The estimates of reserves and resources stated herein for individual properties may not reflect the same confidence level as estimates of reserves and resources for all properties, due to the effects of aggregation.

The Company's total proved and probable reserves at 31 December 2015 plus the estimated reserves associated with the Vorlich licence acquisition from TOTAL, which completed in July 2016, were 57 MMboe. These reserves were independently assessed by Sproule, a qualified reserves evaluator, as of December 31, 2015 in accordance with the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Engineers (Calgary Chapter), as amended from time to time.

The Vorlich field interest and estimated reserves reflect assumed unitisation across licences P1588 and P363. Estimates of the gross 1C to 3C contingent resource (Development Pending) range associated with the Austen discovery have been prepared by Ithaca, effective as of 1 July 2016, and not by an independent qualified reserves evaluator or assessor. These figures are estimates only and the actual results may be greater than or less than the estimates provided herein, with the resource range reflecting uncertainties and risks associated with compartmentalisation of the reservoir. There is no certainty that it will be commercially viable to produce any portion of these resources.

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 2015, (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 available debt capacity and ability to drawdown on the Facilities is based on the Company meeting certain covenants including coverage ratio tests, liquidity tests and development funding tests. The available debt capacity is redetermined semi-annually, using a detailed economic model of the Company and forward looking assumptions of which future oil and gas prices, costs and production profiles are key components. Movements in any component, including movements in forecast commodity prices can therefore have a significant impact on available debt capacity and limit the Company's ability to borrow. There can be no assurance that the Company will satisfy such tests in the future in order to have access to adequate 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 defaults on the Facilities.

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

The Company routinely produces detailed cashflow forecasts to monitor its compliance with the financial and liquidity tests of the Facilities and maintain the ability to execute proactive debt positive actions such as additional commodity hedging.

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: Where appropriate, a cash call process is 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 Shell Trading International Ltd or BP Oil International Limited. Gas production is sold through contracts with Hartree Partners Power and Gas Company (UK) Limited, Shell UK Ltd. and Esso Exploration & Production UK Ltd. Each of these parties has historically demonstrated their ability to pay amounts owing to Ithaca.

Property Risk

RISK: The Company's properties will be generally held in the form of licences, 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 licences, 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 offshore 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

Forward-Looking Information Advisories

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;

· 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 the potential sources thereof;

· The continued availability of the Facilities;

· Funding requirements prior to Stella start up;

· The sufficiency of the Facilities, cash balances and forecast cash flow to cover anticipated future commitments;

· Expected future net debt and continued deleveraging;

· The timing of Stella first hydrocarbons;

· Stella production ramp up time following first hydrocarbons;

· Stella commissioning, offshore hook up and drilling plans;

· 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 anticipated effects of securing access to the GSA oil export pipeline;

· The anticipated timing for completion of licence acquisitions;

· Expected future payments associated with licence acquisitions;

· Statements related to reserves and resources other than reserves;

· Development plans associated with pending licence acquisitions, including field development plans and the planned independent assessment of the Austen property;

· Anticipated benefits of development programmes;

· Anticipated cost to develop portfolio investment opportunities;

· Potential investment opportunities and the expected development costs thereof;

· 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 optimise 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;

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

· Estimates of production volumes and reserves in connection with acquisitions and certain projects

· Estimated decommissioning liabilities;

· The timing and effects of planned maintenance shutdowns;

· The expected impact on the Company's financial statements resulting from changes in tax rates;

· The Company's expected tax horizon;

· Anticipated cost exposure resulting from third party circumstances.

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, both by the Company and its business partners, is obtained within expected timeframes;

· Ithaca's ability to receive necessary regulatory and partner approvals in connection with acquisitions and dispositions;

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

· The market for potential opportunities from time to time and the Company's ability to successfully pursue opportunities;

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

· The timing of anticipated shutdowns;

· Reserves volumes assigned to Ithaca's properties;

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

· Revenues do not decrease significantly 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 and the terms of such funding;

· 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 satisfying conditions to closing acquisitions and dispositions;

· 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 licences;

· 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 or court 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 12 August 2016. The Q2 2016 results have been compared to the results of the comparative period in 2015. This MD&A should be read in conjunction with the Company's unaudited consolidated financial statements as at 30 June 2016 and 2015 together with the accompanying notes and Annual Information Form ("AIF") for the year ended 31 December 2015. These documents, and additional information regarding Ithaca, are available electronically from the Company's website (www.ithacaenergy.com) or SEDAR profile at www.sedar.com.

Consolidated Statement of Income

For the three and six months ended 30 June 2016 and 2015

(unaudited)

Three months ended 30 June

Six months ended 30 June

Note

2016

US$'000

2015

US$'000

2016

US$'000

2015

US$'000

Revenue

5

 24,511

 59,152

57,761

129,527

- Operating costs

(21,848)

(29,499)

(42,033)

(57,622)

- Movement in oil and gas inventory

17,314

3,068

10,990

(13,123)

- Depletion, depreciation and amortisation

(19,776)

(31,702)

(37,384)

(62,259)

Cost of sales

(24,310)

(58,133)

(68,427)

(133,004)

Gross Profit/ (Loss)

201

1,019

(10,666)

(3,477)

Exploration and evaluation expenses

10

(399)

(28,057)

(819)

(29,101)

Gain on disposal

-

25,237

-

25,237

(Loss)/gain on financial instruments

26

(33,453)

(9,831)

(28,274)

19,291

Administrative expenses

6

(1,522)

(1,906)

(3,291)

(5,491)

Foreign exchange

405

(2,513)

906

(4,009)

Finance costs

7

(9,334)

(10,775)

(18,507)

(20,895)

Interest income

20

-

49

50

(Loss) Before Tax

(44,082)

(26,826)

(60,602)

(18,395)

Taxation

24

32,614

66,714

66,848

32,203

(Loss)/ Profit After Tax

(11,468)

39,888

6,246

13,808

Earnings per share

Basic

23

(0.03)

0.12

0.02

0.04

Diluted

23

(0.03)

0.12

0.02

0.04

Consolidated Statement of Financial Position

(unaudited)

30 June

31 December

Note

2016

US$'000

2015

US$'000

ASSETS

Current assets

Cash and cash equivalents

25,852

11,543

Accounts receivable

8

258,833

223,006

Deposits, prepaid expenses and other

2,001

743

Inventory

9

31,802

20,900

Derivative financial instruments

27

46,579

126,887

365,067

383,079

Non current assets

Long-term receivable

29

60,261

61,052

Long-term inventory

9

7,908

7,908

Investment in associate

13

18,337

18,337

Exploration and evaluation assets

10

11,541

11,223

Property, plant & equipment

11

1,092,584

1,102,046

Deferred tax assets

420,654

355,726

Goodwill

12

123,510

123,510

1,734,795

1,679,802

Total assets

2,099,862

2,062,881

LIABILITIES AND EQUITY

Current liabilities

Trade and other payables

15

(323,398)

(275,907)

Exploration obligation

16

(4,000)

(4,000)

Contingent consideration

20

(4,000)

(4,000)

Derivative financial instruments

27

(5,271)

-

(336,669)

(283,907)

Non current liabilities

Borrowings

14

(623,260)

(666,130)

Decommissioning liabilities

17

(231,597)

(226,915)

Other long term liabilities

18

(106,921)

(92,543)

Derivative financial instruments

27

-

(197)

(961,778)

(985,785)

Net Assets

801,415

793,189

Shareholders' equity

Share capital

21

617,721

617,375

Share based payment reserve

22

24,312

22,678

Retained earnings

159,382

153,136

Total equity

801,415

793,189

The financial statements were approved by the Board of Directors on 12 August 2016 and signed on its behalf by:

"Les Thomas"

Director

 "Alec Carstairs"

Director

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

Consolidated Statement of Changes in Equity

(unaudited)

Share Capital

Share based

payment

reserve

Retained Earnings

Total

US$'000

US$'000

US$'000

US$'000

Balance, 1 Jan 2015

551,632

19,234

274,141

845,007

Share based payment

 -

2,018

 -

2,018

Profit for the period

 -

 -

13,808

13,808

Balance, 30 June 2015

551,632

21,252

287,949

860,833

Balance, 1 Jan 2016

617,375

22,678

153,136

793,189

Share based payment

-

1,634

-

1,634

Shares exercised

346

-

-

346

Profit for the period

-

 -

6,246

6,246

Balance, 30 June 2016

617,721

24,312

159,382

801,415

Consolidated Statement of Cash Flow

For the three and six months ended 30 June 2016 and 2015

(unaudited)

Three months ended 30 June

Six months ended 30 June

2016

US$'000

2015

US$'000

2016

US$'000

2015

US$'000

CASH PROVIDED BY (USED IN):

Operating activities

Loss Before Tax

(44,082)

(26,826)

(60,602)

(18,395)

Adjustments for:

Depletion, depreciation and amortisation

11

19,776

31,702

37,384

62,259

Exploration and evaluation expenses

 10

399

28,057

819

29,101

Onerous contracts

-

(8,611)

-

(20,002)

Share based payment

21

220

209

331

389

Loan fee amortisation

7

1,040

1,881

2,078

3,058

Revaluation of financial instruments

26

51,588

41,661

85,153

91,216

Gain on disposal

-

(25,237)

-

(25,237)

Accretion

17

2,294

2,261

4,567

4,499

Bank interest & charges

6,000

6,632

11,861

13,339

Cashflow from operations

37,235

51,729

81,591

140,227

Changes in inventory, receivables and payables relating to operating activities

(1,604)

(4,169)

393

25,086

Petroleum Revenue Tax refunded / ( paid)

324

(2,711)

(916)

(4,443)

Corporation Tax refunded

 -

-

6,009

-

Net cash from operating activities

35,955

44,849

87,079

110,698

Investing activities

Capital expenditure

(17,306)

(57,700)

(26,124)

(117,946)

Loan to associate

316

(679)

1,001

(462)

Decommissioning

17

(128)

 -

(2,165)

-

Changes in receivables and payables relating to investing activities

7,131

(14,130)

1,335

(29,293)

Net cash used in investing activities

(9,987)

(72,509)

(25,953)

(147,701)

Financing activities

Proceeds from issuance of shares

346

-

 346

-

Loan (repayment)/draw down

(20,000)

28,908

(45,000)

55,188

Bank interest and charges

(1,401)

(1,732)

(1,401)

(11,311)

Net cash from financing activities

(21,055)

27,176

(46,055)

43,877

Currency translation differences relating to cash

(920)

(2)

(760)

(833)

Increase / (decrease) in cash and cash equiv.

3,993

(486)

14,309

6,041

Cash and cash equivalents, beginning of period

21,859

25,909

11,543

19,381

Cash and cash equivalents, end of period

25,852

25,423

25,852

25,423

Three months ended 30 June

Six months ended 30 June

2016

US$'000

2015

US$'000

2016

US$'000

2015

US$'000

Oil sales

23,504

57,404

55,534

125,675

Gas sales

824

1,841

1,895

3,240

Condensate sales

150

136

278

289

Other income

33

(229)

54

323

24,511

59,152

57,761