Q1-2016 Financial Results

HIGHLIGHTS FIRST QUARTER 2016

Resilient cashflow generation during the quarter

· Average production of 8,997 barrels of oil equivalent per day ("boepd"), in line with full year guidance (Q1 2015: 12,489 boepd)

· $44.4 million cashflow from operations driven by reduced operating costs and hedging gains despite significant fall in Brent to 12 year low in Q1 2016

· Cashflow per share $0.11 (Q1 2015: $0.27)

· Earnings of $17.7 million (Q1 2015: $26.1 million loss)

Material near term step change in production and cashflow from the GSA

· On track for first production from the Stella field in September 2016 with FPF-1 sail-away in June 2016, in line with previous guidance

· Production set to more than double to 20-25,000 boepd

· Company unit operating costs set to reduce to $20 per barrel of oil equivalent ("boe")

· Further strengthening of the Greater Stella Area ("GSA") portfolio secured with the acquisition of a strategic non-operated interest in the Vorlich discovery

Continued deleveraging and strong liquidity position

· Solid liquidity position maintained with substantial deleveraging commenced before first hydrocarbons from the GSA - net debt reduced by 21% from a peak of over $800 million in 2015 to $630 million at end Q1 2016

· Semi-annual borrowing base review successfully completed in April 2016, maintaining in excess of $100 million of funding headroom

· Available bank debt capacity of over $430 million with total debt capacity of $730 million including $300 million senior unsecured notes due July 2019

Well positioned for lower price environment

· Continuing focus on operating expenditure reductions - unit operating cost outperformance of $25/boe in Q1 2016, a 24% reduction on Q1 2015 (Q1 2015: $33/boe) and 17% ahead of targeted 2016 levels

· Significant commodity price protection - 8,800 boepd hedged from end Q1 2016 until mid-2017 at an average price of $61/boe, with a mark-to-market value of $94 million at end Q1 2016

· Flexibility and control over a modest future capital expenditure profile

SUMMARY STATEMENT OF INCOME

(1) Average realised price before hedging

(2) Revenue net of stock movements

(3) Comparative excludes the one-off acceleration of hedging gains of $59.7 million

SUMMARY BALANCE SHEET

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

CORPORATE STRATEGY

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

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

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

· Maximising cashflow and production from the existing asset base

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

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

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

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

CORPORATE ACTIVITIES

Planned April 2016 RBL redetermination successfully completed - over $100M of headroom maintained

BANK DEBT FACILITIES

In April 2016 the Company successfully completed its routine semi-annual reserves based lending ("RBL") facilities review, continuing to maintain in excess of $100 million of funding headroom 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 bank debt 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 Q1 2016 of $630 million.

The Company continues to focus on maintaining a solid liquidity position, with substantial deleveraging having already commenced even before first hydrocarbons from the GSA. Total bank debt has been reduced by 34% from a peak of over $500 million in the first half of 2015 to $330 million at the end of Q1 2016. A robust financial position has been retained during this 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.

The Company has in place two bank debt facilities, maturing September 2018, totalling $650 million; a senior RBL facility of up to $575 million and a junior RBL facility of up to $75 million. The RBL facilities will commence amortisation on 1 January 2017 from $650 million to $575 million, however this is of no consequence given current RBL debt capacity of approximately $430 million is substantially below this level. 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 senior management changes have been made since the start of the year. In January 2016, Dr Richard Smith was appointed to the executive team as Chief Commercial Officer, following five years as the Company's Corporate Development Manager. Dr Smith has over 19 years of experience in the oil and gas industry and wider energy sector, in various senior business development, corporate strategy and commercial positions. In April 2016, following over 10 years as part of Ithaca's executive team, Nick Muir, Chief Technical Officer left the company.

PRODUCTION & OPERATIONS

Q1 2016 production performance in line with full year guidance

Average production in Q1 2016 was 8,997 boepd, 91% oil (Q1 2015: 12,489 boepd), in line with guidance. This represented a 28% decrease on Q1 2015, reflecting the cessation of production from the Athena and Anglia fields and reduced production due to planned maintenance activities on the Pierce field and and completion of a chemical treatment campaign on several wells in the Dons Area fields. The 2016 Pierce field maintenance shutdown was accelerated into the quarter in order to take advantage of the current period of restricted production rates resulting from the need to complete remedial works on the subsea gas injection flowline for the field. Those works are progressing as planned and it is anticipated that full production from the field will be restored later in the second quarter of 2016 ("Q2 2016").

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.

Production in Q2 2016 is expected to remain in line with full year guidance, with increased volumes associated with the recommencement of full production on the Pierce field broadly offsetting reduced production from the Dons and Causeway Area fields resulting from a planned two week shutdown of the Brent system in June 2016.

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.

GREATER STELLA AREA DEVELOPMENT

GSA development activities are at an advanced stage of completion - Stella production start-up scheduled for Q3 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.

Main FPF-1 commissioning nearing completion - guidance unchanged, with sail-away forecast for June 2016

FPF-1 Modification Works

The FPF-1 modifications programme, which is being undertaken by Petrofac in the Remontowa shipyard in Poland, is on track for first production from the Stella field in September 2016 with FPF-1 sail-away in June, in line with the previous guidance window. Commissioning operations on the vessel are well advanced, and close out of the marine work to ensure the vessel satisfies the required sail-away certification standards is progressing to plan. Completion of the modifications programme is the critical path item for start-up of production from the Stella field.

Handover of the various processing, utilities and accommodation systems on the vessel from the modifications to the operations teams is on-going. The next key milestone will be the completion of deep water trials immediately prior to commencing the tow to the field. This involves the FPF-1 being moved to a location off the coast of Gdansk in order to undertake the necessary marine system commissioning trials that cannot be done in the shallow waters of the shipyard.

It is anticipated that the period from sail-away to first hydrocarbons will be approximately three months. Following towing of the FPF-1 to the field, the vessel 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.

All subsea infrastructure required prior to FPF-1 arrival has been installed

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.

GAS SALES PREPAYMENT

In January 2016, as part of the life of field gas sales agreement in place with BP Gas Marketing Limited ("BP") for the sale of gas produced from the Stella and Harrier fields, the company received a £10 million prepayment for future gas sales to BP. This is similar to the arrangements available with Shell Trading International Limited for oil sales.

COMMODITY HEDGING

Significant commodity price protection in place - $94M mark-to-market value at 1 April 2016

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 $39 million gain in Q1 2016, as of 1 April 2016 the Company had 8,800 boepd hedged at an average price of $61/boe for the 15 months to June 2017. This total is comprised of:

· 9,900 boepd (50% oil) at average price of $60/boe for the remaining nine months of 2016

· 7,000 boepd (50% oil) at average price of $62/boe in the first six months of 2017.

The above figures include 114 million therms of gas hedging (approximately 11 billion cubic feet), with a price floor of £0.56/therm (~$8.50/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 April 2016 the Company's commodity hedges were valued at $94 million, $49 million for oil hedges and $45 million for gas hedges, based on valuations relative to the respective oil and gas forward curves.

LICENCE PORTFOLIO ACTIVITIES

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

VORLICH ACQUISITION

In line with Ithaca's strategic objective to increase value from the GSA infrastructure through the acquisition of interests in potential satellite fields for the FPF-1, the Company signed a sale and purchase agreement with TOTAL E&P UK Limited in January 2016 to obtain a 20% non-operated interest in Licence P363 (block 30/1c), effective 1 July 2015. The licence is operated by BP plc and contains approximately 80-90% of the Vorlich discovery, implying an approximately 17% interest in the overall discovery to Ithaca. Vorlich is located 10 kilometres north of the GSA hub. 

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.

In accordance with the requirements of the Vorlich licence, the work programme for 2016 is centred on the preparation and submission for approval of a Field Development Plan ("FDP") by the end of the year.

A minimal consideration is payable at completion of the transaction, with additional contingent payments at FDP approval and upon reaching a reserves recovery threshold. The acquisition is subject to normal regulatory approvals and is expected to complete later in the second quarter of 2016.

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). This brings the Company's total interest in the field to 21.4%. The Company does not expect any significant cost exposure as a result of First Oil's default other than the associated incremental decommissioning liability, which is currently estimated to be $1.9 million.

OPERATING EXPENDITURE

Unit operating costs $25/boe in Q1 2016,24% lower than Q1 2015

Operating costs in Q1 2016 continued on the downward trend established in 2015, with a unit cost of $25/boe delivered during the quarter. 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.

The continued downward cost pressure increases the likelihood of achieving a sub $30/boe unit cost for the existing producing fields during the year.

CAPITAL EXPENDITURE

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

Total capital expenditure in Q1 2016 was $3.6 million. Total 2016 capital expenditure is anticipated to be approximately $50 million (2015: $117 million), the majority of which relates to the GSA, including activities required to prepare the Vorlich FDP for approval.

Beyond 2016, Ithaca forecast an average underlying capex 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.

DEBT

Further deleveraging in 2016 - net debt reduced to $630M at end Q1 2016

The Company commenced deleveraging the business in 2015. Net debt has reduced from a peak of over $800 million in the first half of 2015 to $630 million at 31 March 2016. This reduction reflects the benefit of strong operating cashflow generation, lower capital expenditures, the cash received from sale of the non-core Norwegian business, as well as proceeds of the premium equity placing completed in October 2015. 

Deleveraging of the business continues to remain a core priority of the Company, with a step change in the debt reduction profile achievable upon the start-up of Stella production.

Q1 2016 RESULTS OF OPERATIONS

COMMODITY PRICES

The Q1 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 $20/bbl or 37% between Q1 2015 and Q1 2016. 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 price hedging protection the Company had put in place.

REVENUE

Revenue decreased by $37.2 million in Q1 2016 to $33.2 million (Q1 2015: $70.4 million) as a consequence of a $22/bbl or 38% decrease in the realised oil price prior to taking into account hedging, combined with a 27% reduction in sales volumes.

Both produced and sold volumes decreased by approximately 27% in Q1 2016 compared to Q1 2015 (refer to the Production & Operations section above). The decrease was primarily driven by the cessation of production from the Athena and Anglia fields. Volumes were also reduced by planned Pierce shutdown activities, lower Dons Area production due to scheduled well maintenance activities and natural field decline rates.

The reduction in realised price for the period was offset to a significant extent by realised oil and gas hedging gains of $41 per sales barrel of oil equivalent in the quarter, resulting in a $38.7 million gain being reported through Foreign Exchange and Financial Instruments (see below).

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.

COST OF SALES

Cost of sales decreased in Q1 2016 by over 40% to $44.1 million (Q1 2015: $74.9 million). This was primarily attributable to decreases in operating costs, depletion, depreciation and amortisation ("DD&A") and to a lesser extent by movement in oil and gas inventory.

OPERATING EXPENDITURE

Reported operating costs decreased by 28% in the quarter to $20.2 million (Q1 2015: $28.1 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 costs delivered a unit operating cost of $25/boe for Q1 2016, representing a reduction of 24% compared to the equivalent rate of $33/boe for Q1 2015 and 17% ahead of targeted 2016 levels of $30/boe prior to first oil from the Stella field.

DD&A

The unit DD&A rate for the quarter decreased to $21/boe (Q1 2015: $27/boe), resulting in a total DD&A expense for the period of $17.6 million (Q1 2015: $30.6 million). This reduction in expense was due to a combination of lower production in the quarter 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 $6.3 million was charged to cost of sales in Q1 2016 (Q1 2015: charge of $16.2 million). This charge arose as a result of an overlift in the quarter, predominantly due to the lifting and sale of the inventory positions on the Cook and Wytch Farm fields built up in Q4 2015. The pricing of inventory has remained broadly constant from the end of 2015.

ADMINISTRATION EXPENSES AND EXPLORATION & EVALUATION EXPENSES

Administration expenses reduced through on-going cost reduction measures

ADMINISTRATION EXPENSES

Total administrative expenses were reduced by 51% to $1.8 million in Q1 2016 (Q1 2015: $3.6 million). This step change was largely attributable to the sale of the Norwegian operations in July 2015, as the Q1 2015 administrative expenses includes approximately $1.3 million (pre-tax) of overhead costs associated with those operations (the Q1 2015 costs were recovered as part of conventional adjustments at completion of the transaction). The reduction in expenses is also due to a continued focus on cost saving initiatives across the business, with costs during the quarter also reflecting further reductions in contractor rates and a decrease in both employee and contractor numbers.

E&E EXPENSES

A minor write off of E&E assets was made at the period end relating to non-commercial prospects.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

A modest foreign exchange gain of $0.5 million was recorded in Q1 2016 (Q1 2015: $1.5 million loss). 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, with the rate moving from 1.48 at 1 January 2016 to 1.44 at 31 March 2016 and fluctuations throughout the quarter of between 1.39 and 1.48, is the primary factor underlying foreign exchange gains and losses.

The Company recorded an overall gain of $5.2 million on financial instruments for the quarter ended 31 March 2016 (Q1 2015: $29.1 million gain).

A $38.7 million realised gain was made in Q1 2016. This comprised a $22.8 million gain on oil hedges maturing during the quarter (at an average exercise price of $61/bbl compared to an average Brent price of $34/bbl) and a $16.4 million gain on gas hedges, partially offset by a $0.4 million loss on foreign exchange instruments. The total realised gain of $38.7 million was reduced by a $33.6 million negative revaluation of instruments as at 31 March 2016. This resulted from a negative revaluation of oil hedges of $19.4 million, gas hedges of $12.9 million and other hedges of $1.2 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 $19.4 million negative revaluation of oil hedges was due to the realisation of hedged oil volumes during the quarter i.e. the transfer of previously unrealised gains to realised gains, with the realised gain being inflated due to exceptionally low Brent prices in January and February. The negative revaluation of gas hedges mainly related to the realisation of hedged gas volumes during the quarter, partially offset by an increase in the value of the remaining gas hedges at the end of Q1 2016 due to a decrease in the gas price forward curve.

As of 1 April 2016, the Company's commodity hedges were valued at $94 million, $49 million for oil hedges and $45 million for gas hedges, based on valuations relative to the respective oil and gas forward curves.

FINANCE COSTS

Reducing finance cost profile driven by decreasing net debt

Finance costs decreased to $9.2 million in Q1 2016 (Q1 2015: $10.1 million). This reduction is primarily attributable to the decrease in RBL bank interest resulting from a significant deleveraging of the business over the last twelve months, with drawn debt reducing from $502 million at 31 March 2015 to $352 million at 31 March 2016. All other finance costs have remained relatively stable quarter on quarter.

TAXATION

No UK tax anticipated to be payable prior to 2020

A tax credit of $34.2 million was recognised in the three months ended 31 March 2016 (Q1 2015: $34.5 million charge). Significant adjustments to the $10.1 million Corporation Tax ("CT") credit include a $14.2 million credit relating to the UK Ring Fence Expenditure Supplement and $3.5 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 Q1 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 the rate of 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 has been fully released through the Q1 2016 results giving rise to a credit of $24.2 million.

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 later in 2016 when the rate change is enacted.

The Q1 2015 UK and Norway credit reflected a deferred tax charge of $41.5 million relating to reductions in the SCT and PRT rates enacted in that period. It was announced in the UK Budget in March 2015 that the effective CT rate on oil and gas companies would 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 $50.9 million relating to deferred Corporation Tax, partially offset by a credit of $10.6 million relating to the impact of a reduction in the PRT rate from 50% to 35% on the deferred PRT liability in the balance sheet.

As a result of the above factors, the loss before tax of $16.5 million becomes a profit after tax of $17.7 million (Q1 2015: $26.1 million loss).

CAPITAL INVESTMENTS

2016 capital investment programme primarily focused on GSA development activities

The major capital additions in the period related to development and production ("D&P") assets and totalled $11.1 million. Excluding capitalised interest costs and non-cash additions relating to decommissioning, capital expenditure was approximately $3.6 million.

WORKING CAPITAL

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

As at 31 March 2016 Ithaca had a net working capital balance of $94.6 million, including an unrestricted cash balance of $21.9 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. As noted earlier, First Oil went into administration during the quarter however the Company does not anticipate any significant cost exposure as a result of this.

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 three month period to 31 March 2016 mainly as a result of a reduction in the commodity hedging instrument asset values due to realisations during the quarter.

CAPITAL RESOURCES

Bank debt facilities successfully redetermined in April 2016. Net debt reduced to $630 million at end Q1 2016

DEBT FACILITIES

At 31 March 2016 Ithaca had two UK bank debt facilities, being the $575 million senior RBL Facility and the $75 million junior RBL Facility, both due September 2018. Following completion of the April 2016 RBL redetermination process the Company's available bank debt capacity was set at over $430 million (out of the total $650 million of RBL facilities). Further information is provided in the "Corporate Activities" section above. The Company also has $300 million senior unsecured notes, due July 2019.

The Company's bank 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 Q1 2016

Q1 2016 CASHFLOW MOVEMENTS

During the three months ended 31 March 2016 there was a cash inflow from operating, investing and financing activities of approximately $10.3 million (Q1 2015 inflow of $6.5 million.

Cashflow from operations

Cash generated from operating activities was $44.4 million. Revenues from the producing portfolio of assets were bolstered by the substantial hedging programme in place while operating costs reduced by almost 30% quarter on quarter.

Cashflow from financing activities

Cash used in financing activities was $25.0 million, being repayments of the debt facilities during the quarter.

Cashflow from investing activities

Cash used in investing activities was $10.2 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 ongoing operational commitments on the Pierce and Dons assets. 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 31 March 2016.

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 31 March 2016.

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

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 £3.2 million per month hedged at a forward rate of $1.48 : £1 for the period to December 2016.

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

12 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 acquisition of the assets from Sumitomo Corporation in July 2014, are fluctuations in underlying commodity prices and movement in production volumes. The Company has utilised forward sales 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 USD: GBP 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 31 March 2016 Ithaca had 411,384,045 common shares outstanding along with 30,816,206 options outstanding to employees and directors to acquire common shares.

In Q1 2016 the Company's Board of Directors granted 12,000,000 options at a weighted average exercise price of C$0.55. Each of the options granted may be exercised over a period of four years from the grant date. One third of the options will vest at the end of each of the first, second and third years from the effective date of grant.

(1) Represents the TSX close price (CAD$0.67) on 31 March 2016. US$:CAD$ 0.77 on 31 March 2016

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 31 March 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, 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 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 31 March 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 31 March 2016, there were no changes in the Company's internal control over financial reporting that occurred during the quarter ended 31 March 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 31 March 2016, finance lease assets of $29.9 million and related liabilities of $30.1 million are included on the balance sheet.

Related Party Transactions

A director of the Company is a partner of Burstall Winger Zammit LLP who acts as counsel for the Company. The amount of fees paid to Burstall Winger Zammit LLP in Q1 2016 was $0.1 million (Q1 2015: $0.1 million). These transactions are in the normal course of business and are conducted on normal commercial terms with consideration comparable to those charged by third parties.

As at 31 March 2016 the Company had loans receivable from FPF-1 Limited and FPU Services Limited, associates of the Company, for $60.5 million and $0.1 million, respectively (31 March 2015: $58.1 million and $Nil, 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.

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 RWE NPower PLC, 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 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 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 sail-away and first hydrocarbons;

· Stella production ramp up time following first hydrocarbons;

· Stella 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;

· 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 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;

· 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 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 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 13 May 2016. The Q1 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 31 March 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 months ended 31 March 2016 and 2015

(unaudited)

2016

2015

Note

US$'000

US$'000

Revenue

5

33,250

70,375

Operating costs

(20,185)

(28,123)

Movement in oil and gas inventory

(6,325)

(16,191)

Depletion, depreciation and amortisation

(17,608)

(30,556)

Cost of sales

(44,118)

(74,870)

Gross (Loss)

(10,868)

(4,495)

Exploration and evaluation expenses

10

(421)

(1,044)

Gain on financial instruments

26

5,179

29,122

Administrative expenses

6

(1,769)

(3,584)

Foreign exchange

502

(1,496)

Finance costs

7

(9,173)

(10,122)

Interest income

29

52

(Loss)/Profit Before Tax

(16,521)

8,433

Taxation

24

34,233

(34,511)

Profit/(Loss) After Tax

17,712

(26,078)

Earnings per share (US$ per share)

Basic

Diluted

23

23

0.04

0.04

(0.08)

(0.08)

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

Consolidated Statement of Financial Position

(unaudited)

31 March

31 December

Note

2016

US$'000

2015

US$'000

ASSETS

Current assets

Cash and cash equivalents

21,859

11,543

Accounts receivable

8

213,793

223,006

Deposits, prepaid expenses and other

5,434

743

Inventory

9

15,057

20,900

Derivative financial instruments

27

94,239

126,887

350,382

383,079

Non-current assets

Long-term receivable

29

60,577

61,052

Long-term inventory

9

7,908

7,908

Investment in associate

13

18,337

18,337

Exploration and evaluation assets

10

11,487

11,223

Property, plant & equipment

11

1,095,507

1,102,046

Deferred tax assets

388,038

355,726

Goodwill

12

123,510

123,510

1,705,364

1,679,802

Total assets

2,055,746

2,062,881

LIABILITIES AND EQUITY

Current liabilities

Trade and other payables

15

(255,808)

(275,907)

Exploration obligation

16

(4,000)

(4,000)

Contingent consideration

20

(4,000)

(4,000)

Derivative financial instruments

27

(1,304)

-

(265,112)

(283,907)

Non-current liabilities

Borrowings

14

(642,183)

(666,130)

Decommissioning liabilities

17

(229,430)

(226,915)

Other long term liabilities

18

(107,352)

(92,543)

Derivative financial instruments

27

-

(197)

(978,965)

(985,785)

Net assets

811,669

793,189

Shareholders' equity

Share capital

21

617,375

617,375

Share based payment reserve

22

23,446

22,678

Retained earnings

170,848

153,136

Total equity

811,669

793,189

The financial statements were approved by the Board of Directors on 13 May 2016 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.

(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

-

1,123

-

1,123

Loss for the period

-

-

(26,078)

(26,078)

Balance, 31 March 2015

551,632

20,357

248,063

820,052

Balance, 1 Jan 2016

617,375

22,678

153,136

793,189

Share based payment

-

768

-

768

Profit for the period

-

 -

17,712

17,712

Balance, 31 March 2016

617,375

23,446

170,848

811,669

(unaudited)

2016

US$'000

2015

US$'000

Operating activities

(Loss)/Profit Before Tax

(16,521)

8,433

Adjustments for:

Depletion, depreciation and amortisation

11

17,608

30,556

Exploration and evaluation write off

10

421

1,044

Onerous contracts

-

(11,391)

Share based payment

21

111

180

Loan fee amortisation

7

1,040

1,177

Revaluation of financial instruments

26

33,565

49,556

Accretion on decommissioning provisions

2,273

2,238

Bank interest & charges

5,861

6,707

Cashflow from operations

44,358

88,500

Changes in inventory, debtors and creditors relating to operating activities

1,997

(20,197)

Petroleum Revenue Tax paid

(1,240)

(1,732)

Corporation Tax refunded

6,009

-

Net cash from operating activities

51,124

65,851

Investing activities

Capital expenditure

(8,818)

(60,246)

Loan to associate

 685

217

Decommissioning

(2,037)

-

Changes in debtors and creditors relating to investing activities

(5,796)

(15,163)

Net cash (used in) investing activities

(15,966)

(75,192)

Financing activities

Loan (repayment)/draw down

(25,000)

26,280

Bank interest and charges

-

(9,579)

Net cash from financing activities

(25,000)

16,701

Currency translation differences relating to cash & cash equivalents

158

(832)

Increase in cash and cash equivalents

10,316

6.528

Cash and cash equivalents, beginning of period

11,543

19.381

Cash and cash equivalents, end of period

21,859

25,909

1.

NATURE OF OPERATIONS

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

2.

BASIS OF PREPARATION

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

The policies applied in these condensed interim consolidated financial statements are based on IFRS issued and outstanding as of 13 May 2016, the date the Board of Directors approved the statements. Any subsequent changes to IFRS that are given effect in the Corporation's annual consolidated financial statements for the year ending 31 December 2016 could result in restatement of these interim consolidated financial statements.

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

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

The condensed interim consolidated financial statements should be read in conjunction with the Corporation's annual financial statements for the year ended 31 December 2015.

3.

SIGNIFICANT ACCOUNTING POLICIES, JUDGEMENTS AND ESTIMATION UNCERTAINTY

Basis of measurement

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

Basis of consolidation

The interim consolidated financial statements of the Corporation include the financial statements of Ithaca Energy Inc. and all wholly-owned subsidiaries as listed per note 29. Ithaca has twenty wholly-owned subsidiaries. All inter-company transactions and balances have been eliminated on consolidation.

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

Business Combinations

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

Goodwill

Capitalisation

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

Impairment

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

Interest in joint operations

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

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

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

Revenue

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

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

Foreign currency translation

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

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

Share based payments

The Corporation has a share based payment plan as described in note 21 (c). The expense is recorded in the consolidated statement of income or capitalised for all options granted in the year, with the gross increase recorded in the share based payment reserve. Compensation costs are based on the estimated fair values at the time of the grant and the expense or capitalised amount is recognised over the vesting period of the options. Upon the exercise of the stock options, consideration paid together with the amount previously recognised in share based compensation reserve is recorded as an increase in share capital. In the event that vested options expire unexercised, previously recognised compensation expense associated with such stock options is not reversed. In the event that unvested options are forfeited or expired, previously recognised compensation expense associated with the unvested portion of such stock options is reversed.

Cash and cash equivalents

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

Financial instruments

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

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

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

Analyses of the fair values of financial instruments and further details as to how they are measured are provided in notes 26 to 28.

Inventory

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

Trade receivables

Trade receivables are recognised and carried at the original invoiced amount, less any provision for estimated irrecoverable amounts.

Trade payables

Trade payables are measured at cost.

Property, plant and equipment

Oil and gas expenditure - exploration and evaluation assets

Capitalisation

Pre-acquisition costs on oil and gas assets are recognised in the consolidated statement of income when incurred. Costs incurred after rights to explore have been obtained, such as geological and geophysical surveys, drilling and commercial appraisal costs and other directly attributable costs of exploration and evaluation including technical, administrative and share based payment expenses are capitalised as intangible exploration and evaluation ("E&E") assets.

E&E costs are not amortised prior to the conclusion of evaluation activities. At completion of evaluation activities, if technical feasibility is demonstrated and commercial reserves are discovered then, following development sanction, the carrying value of the E&E asset is reclassified as a development and production ("D&P") asset, but only after the carrying value is assessed for impairment and where appropriate its carrying value adjusted. If after completion of evaluation activities in an area, it is not possible to determine technical feasibility and commercial viability or if the legal right to explore expires or if the Corporation decides not to continue exploration and evaluation activity, then the costs of such unsuccessful exploration

and evaluation are written off to the statement of income in the period the relevant events occur.

Impairment

The Corporation's oil and gas assets are analysed into CGU for impairment review purposes, with E&E asset impairment testing being performed at a grouped CGU level. The current E&E CGU consists of the Corporation's whole E&E portfolio. E&E assets are reviewed for impairment when circumstances arise which indicate that the carrying value of an E&E asset exceeds the recoverable amount. When reviewing E&E assets for impairment, the combined carrying value of the grouped CGU is compared with the grouped CGU's recoverable amount. The recoverable amount of a grouped CGU is determined as the higher of its fair value less costs to sell and value in use. Impairment losses resulting from an impairment review are written off to the statement of income.

Oil and gas expenditure - development and production assets

Capitalisation

Costs of bringing a field into production, including the cost of facilities, wells and sub-sea equipment, direct costs including staff costs and share based payment expense together with E&E assets reclassified in accordance with the above policy, are capitalised as a D&P asset. Normally each individual field development will form an individual D&P asset but there may be cases, such as phased developments, or multiple fields around a single production facility when fields are grouped together to form a single D&P asset.