IAE.L Regulatory News (IAE)

2016 HIGHLIGHTS

Solid cashflow generation in the year

· Average production of 9,310 barrels of oil equivalent per day ("boepd"), ahead of full year guidance of 9,000 boepd (2015: 12,066 boepd)

· Unit operating expenditure reduced to $23/boe in 2016 (2015: $31/boe)

· 2016 cashflow from operations of $147 million, down from $240 million in 2015

· Loss after tax of $54 million, impacted by the reduction in UK tax rates during the year (2015: $121 million)

· Downside commodity price hedging in place to mid-2018 - 7,600 boepd at an average floor of $50/boe

· Net debt reduced to $598 million at year-end 2016, down from $665 million at the start of 2016

· Refinancing of the Company's debt facilities anticipated during 2017

· Proved and probable reserves, as independently evaluated by Sproule1, increased to 76 MMboe, primarily as a result of the Vorlich and Austen licence acquisitions and updated portfolio work programmes

Stella first oil achieved on 16 February 2017

· Stella field started up in February 2017 - production to date approximately 1,700 barrels of oil equivalent per day net to Ithaca

· FPF-1 dynamic commissioning programme on-going - producing at reduced rates to minimise gas flaring until the gas processing systems are fully commissioned

· Harrier field development programme underway - development drilling to be completed in 2017, with start-up of production expected in the second half of 2018

Delek Offer -opportunity for shareholders to crystallise full value of their investments at a premium cash price

· Takeover offer by DLK Investments Limited, a wholly owned subsidiary of Delek Group Limited("Delek"), announced on 6 February 2017 for a cash consideration of C$1.95 per share, which equates to approximately £1.19 per share2

· Acceptance of the offer is unanimously recommended by the Board of Directors (excluding the Delek related party directors) based on a number of factors including an evaluation of the fullness of the offer relative to the future upsides and execution risks of the business

· Shareholder circulars distributed and closing of initial deposit period set as 17.00 (Toronto time) on 20 April 2017 - the offer is conditional upon, amongst other things, more than 50% of the shares outstanding that are not currently owned by the Offeror and its affiliates being deposited

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

· 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

Unanimously recommended takeover by Delek

RECOMMENDED DELEK TAKEOVER OFFER

On 6 February 2017 the Company announced that it had entered into a definitive support agreement with Delek Group Ltd ("Delek") on the terms of a cash takeover bid for all of the issued and to be issued common shares of Ithaca not currently owned by Delek or any of its affiliates for C$1.95 per share (the "Offer").

The Offer is being made by DKL Investments Limited (the "Offeror"), an affiliate of Delek, which is currently Ithaca's largest shareholder and holds approximately 19.7% of the currently issued and outstanding common shares of the Company.

The Board of Directors excluding the Delek related party directors (the "Directors"), after consulting with its financial and legal advisers, considers the terms of the Offer to be in the best interests of Ithaca and its shareholders and accordingly unanimously recommends that shareholders accept the Offer and deposit their shares. A principal reason for this recommendation is centred on an evaluation of the fullness of the Offer relative to the future upsides and execution risks of the business.

A full explanation of the reasons underlying the recommendation to shareholders and the multiple factors evaluated by Directors is contained in the Directors' Circular that was issued to shareholders on 14 March 2017 and is available on the Company's Sedar profile at Sedar.com. The evaluation and its conclusion was made in light of the Directors' own knowledge of the business, the industry and the financial condition and prospects of the Company and based upon the recommendation of a special committee of independent directors ("the Special Committee"), which has been advised by RBC Capital Markets ("RBC") in its capacity as financial advisor to the Company.

The Offer will be open for acceptance until 17.00 (Toronto time) on 20 April 2017 (the "Expiry Time"). Shareholders wishing to accept the Offer must take action to deposit their shares.

Successful completion of the Offer is conditional upon, amongst other things, more than 50% of the common shares outstanding (excluding the shares already owned by the Offeror and its affiliates) being validly deposited under the Offer prior to the Expiry Time (the "Minimum Tender Condition"). No deposited shares will be purchased by the Offeror if the Minimum Tender Condition is not satisfied.

Planned 2016 RBL redeterminations successfully completed - over $110M of headroom in place at end 2016

DEBT FACILITIES

The Company completes a semi-annual redetermination process with its reserves based lending ("RBL") bank syndicate, at the end of April and October of each year, to review the borrowing capacity of its assets based on the technical and commodity price assumptions applied by the syndicate. Following the successful completion of the October 2016 redetermination, the Company's available RBL borrowing capacity is over $410 million. When combined with the $300 million senior unsecured notes the Company has in place, the business has a total debt capacity of over $710 million, maintaining in excess of $110 million of funding headroom when compared to net debt at the end of 2016 of $598 million.

The Company is focused on maintaining a solid liquidity position, with substantial deleveraging having already been delivered before Stella first hydrocarbons. 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 in June 2016, saving approximately $0.5 million in commitment fees for the remainder of the year. This change has no effect on the current RBL debt capacity of approximately $410 million, as this is 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.

Ithaca's existing bank debt facilities and senior notes have maturities in late 2018 and mid-2019, respectively. During 2017 the Company will assess the options to refinance these credit facilities and the associated debt maturity profiles.

DIRECTOR & EXECUTIVE CHANGES

Certain director and senior management changes have been made since the start of the year. Following the Company's annual general meeting in June 2016, Jack 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

Solid 2016 production - ahead of full year guidance

2016 PRODUCTION

The producing asset portfolio performed well during 2016, with production running ahead of the 9,000 boepd guidance largely as a result of solid performance from the Cook field. Average production for 2016 was 9,310 boepd, 92% oil (2015: 12,066 boepd), which compares to full year base production guidance of approximately 9,000 boepd.

When comparing 2016 with 2015, production has down by approximately 23%. 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 was also restricted on the Pierce field during the first half of 2016 due to the requirement to complete remedial works on the field's subsea gas injection flowline.

2017 PRODUCTION

Average production in 2017 is anticipated to be in the range of 19,000 to 22,000 boepd (approximately 75% oil). This range reflects the updated Stella start-up schedule, the programme of planned maintenance shutdowns during the year and sensitivities associated with the performance of those operational programmes.

Production in the first quarter of 2017 is forecast to average approximately 9,200 boepd, including the initial contribution from the Stella field since mid-February 2017.

While the on-going dynamic commissioning operations are continuing on the FPF-1, the Stella field is being produced at reduced rates from two of the five wells on the field. As a consequence, average Stella production to date has been approximately 1,700 barrels of oil per day net to Ithaca, with the produced gas being flared until the fuel gas systems have been commissioned.

GREATER STELLA AREA DEVELOPMENT

GSA "hub and spoke" strategy

Ithaca's focus on the Greater Stella Area ("GSA") is driven by monetisation of the Company's existing portfolio of undeveloped discoveries located in the area.

The GSA development involves the creation of a production hub based on deployment of the Ithaca operated FPF-1 floating production facility, which is located over the Stella field, with onward export of oil and gas to market. To maximise initial oil and condensate production and fill the gas processing facilities on the FPF-1, initial production from the hub will come from the Stella field. It is anticipated that further wells will then be drilled and tied back to the FPF-1 on the wider GSA satellite portfolio to maintain the gas processing facilities on plateau.

Stella first hydrocarbons delivered in February 2017 - dynamic commissioning of the gas processing facilities on-going

Stella Development

Following completion of the necessary offshore preparatory works on the FPF-1, first hydrocarbons from the Stella field was achieved in mid-February 2017. Production was initially started from one well on the field in order to commission and stabilise the hydrocarbon processing systems on the FPF-1 and commence oil exports to the adjacent shuttle tanker.

Continued progress is being made with the FPF-1 dynamic commissioning programme. The key outstanding tasks involve commissioning of the fuel gas system and the two gas export compressors, in order to commence gas exports to the CATS pipeline.

Initial load testing on the first of the two gas export compressors identified the requirement for modifications to the instrumentation on the machine in order to complete the commissioning scope. This work is in the process of being completed and it is expected that the planned commissioning programme will shortly recommence. Once load testing of the compressor has been satisfactorily proven, this will enable gas to be routed to the fuel gas system and initial pipeline exports to begin. Following this, testing of the second gas export compressor will commence.

Once both export compressors are operational the ramp-up to full production rates will commence, followed by optimisation of production across the wells on the field. While it was anticipated that the dynamic commissioning and ramp-up programme would take up to eight weeks to complete, it is likely that these activities will take longer, with the ramp-up phase of operations now expected to commence in April 2017.

Switch from oil tanker to pipeline export scheduled for 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 was secured in 2016 for future GSA oil production, allowing a switch from tanker loading to pipeline exports 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. Following this, the 44 kilometre spurline from the FPF-1 to the Norpipe system was installed in September 2016. The main outstanding activities that now remain to be completed are the installation and tie-in of the pipeline export pumps on the FPF-1 and installation of the final subsea connections that need to be undertaken immediately prior to the switchover from shuttle tanker to pipeline export.

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.

Harrier field development drilling to commence in Q2 2017, commencing the build out of the GSA production hub

HARRIER DEVELOPMENT

In line with the Company's strategy for building out the GSA production hub, investment in the Harrier field development programme will commence in 2017. The development involves drilling of a multilateral well into the two reservoir formations on the field, with the well tied back via a 7.5 kilometre pipe to an existing slot on the Stella main drill centre manifold for onward export and processing of production on the FPF-1.

The GSA joint venture has contracted with Ensco Offshore UK Limited for the provision of a heavy duty jack-up drilling rig, which is expected to arrive on location in April 2017. The drilling programme is forecast to be completed in the second half of 2017 and the subsea infrastructure installation activities in summer 2018, resulting in the anticipated start-up of Harrier production in the second half of 2018.

LICENCE PORTFOLIO ACTIVITIES

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 has acquired approximately 33% of the the Vorlich discovery along with a 75% interest and operatorship of the Austen discovery.

VORLICH

In October 2016 the Company completed the acquisition of 100% of licence P1588 (Block 30/1f) through three purchases from ENGIE E&P UK Limited ("ENGIE E&P"), INEOS UK SNS Limited and Maersk Oil North Sea Limited. 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, these transactions increase Ithaca's overall interest in the Vorlich discovery by around 16%, to approximately 33%. The remaining interest is owned by BP, who is also Operator of the Vorlich licence.

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 2016 to contain gross proven and probable undeveloped reserves of approximately 22 MMboe by Sproule. Following completion of the Vorlich appraisal programme in 2014, current activities are focused on planning and preparation of a Field Development Plan ("FDP").

The overall Vorlich licence interests are as follows:

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

· Licence PL1588: Ithaca (Operator), 100%

AUSTEN

In December 2016 an SPA was completed 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.

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.

Operatorship obtained of core producing Cook field in 2016

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.

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 for zero consideration (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

Additional hedging put in place - commodity price protection established for 7,600 boepd to June 2018

As part of its financial and risk management strategy, the Company actively seeks to maintain a balanced commodity hedging position. Any hedging is executed at the discretion of the Company, with no minimum requirements stipulated in any of the Company's debt finance facilities.

In 2016, the Company benefitted from realised commodity hedging gains for the year of $87.9 million, equating to an additional $25 of revenue per sales barrel of oil equivalent in the year.

As of 1 January 2017, the Company has 7,600 boepd (85% oil) hedged at an average floor price of $50/boe for the 18 months to 30 June 2018. Full commodity price upside exposure has been retained on 60% of the volumes hedged and upside exposure to $60/boe has been retained on a further 25% of the hedged volumes. Based on valuations relative to the respective oil and gas forward curves as of 1 January 2017, these hedges were valued at $7.2 million.

RESERVES

Total proved and probable ("2P") reserves as at 31 December 2016 estimated to be 76 MMboe, as independently evaluated by Sproule International Limited, a qualified reserves evaluator, in accordance with the Canadian Oil and Gas Evaluation Handbook pursuant to NI 51-101 - Standards of Reserves Disclosure for Oil and Gas Activities.

The movement in total 2P reserves between end-2015 and end-2016 is set out in the following table. In summary, the Company's 2P reserves have increased during 2016 primarily as a result of the acquisition of the Vorlich and Austen licence interests, coupled with technical revisions for future work programmes on the Cook and Pierce fields.

The 2P reserves post-tax net present value discounted at 10% ("NPV-10") assessed by Sproule as at 31 December 2016 was estimated as $1,528 million, based on forecast Brent prices of $55/bbl in 2017 rising to $70/bbl in 2019 and over $80/bbl in 2026. This represents an unrisked estimate of the value of the individual producing and development assets, including four future GSA development projects, drilling of a water injection well on the Cook field and modification of the Pierce field for the gas blowdown phase of operations.

This Sproule NPV-10 is not a company valuation as it does not take into account the future financial liabilities of the Company or the estimated decommissioning costs associated with assets that have ceased production prior to the date of the evaluation, being Jacky, Athena, Anglia, Causeway and certain well abandonment obligations. The following table, taking account of the factors noted above, sets out the implied unrisked Company post tax net asset value ("NAV") derived from the Sproule evaluation of C$2.03 per fully diluted share.

OPERATING EXPENDITURE

Full year opex under guidance for current producing asset base at $23/boe

Continued operating cost savings have reduced 2016 unit operating costs to $23/boe, down from $31/boe in 2015 and below the $30/boe guidance provided at the start of the year. Cost reductions have been achieved across the portfolio, with the Cook, Pierce and Wytch Farm fields delivering the most significant savings.

Forecast 2017 unit operating expenditure is anticipated to be approximately $18/boe, reflecting the benefit of the start-up of production from the Stella field.

CAPITAL EXPENDITURE

2016 capital expenditure of ~$60M with 2017 expected expenditure of $70M

Total capital expenditure in 2016 was $63 million, in line with the revised guidance issued during the year to reflect inclusion of the expenditure associated with acceleration of the GSA oil pipeline installation operations.

Net 2017 capital expenditure is forecast to total approximately $70 million. The majority of this expenditure relates to the GSA, primarily being Harrier development activities plus completion of the GSA oil export pipeline investment programme and Vorlich field development planning activities. The forecast expenditure is also inclusive of any additional Stella start-up costs, which are expected to be minimal.

NET DEBT

Further deleveraging delivered in 2016 - net debt reduced to $598M at end 2016

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

Net debt was reduced by $67 million in 2016 to $598 million at 31 December 2016. This reduction reflects the benefit of continuing strong operating cashflow generation from the base producing assets delivered as a result of solid production, reduced operating costs and lower capital expenditures across the portfolio.

TRADING ENVIRONMENT

COMMODITY PRICES

The 2016 financial results reflect the impact of the continued reduction in Brent prices that has been a central feature of the sector since the middle of 2014. The average Brent price fell by 15% to $44/bbl in 2016, down from $52/bbl in 2015. While this has had a significant negative impact on revenues, the fall in Brent has been materially mitigated during the period by the significant hedging protection the Company had in place.

FOREIGN EXCHANGE RATES

Volatility in exchanges rates resulting from the UK's decision during 2016 to exit the European Union, has also had a positive impact on the financial results as a consequence of the ensuing devaluation of the pound sterling versus the US dollar. Ahead of the introduction of gas sales from the Stella field the majority of the Company's revenue is US dollar denominated oil sales, while approximately 80% of costs are incurred in pounds sterling. In general, however, the company has sought to minimise currency volatility through active hedging of sterling.

SELECTED ANNUAL INFORMATION

· Revenues have reduced by approximately 30% in 2016 as a result of a decrease in the realised oil price, which was also the main driver behind the reduction in revenues in 2015 compared to 2014, combined with a reduction in underlying sales volumes.

· Total assets decreased from 2015 to 2016 mainly as a result of the decrease in the derivative financial instruments as they unwound and were realised. The cash realised from the derivatives has been used to pay down debt and therefore reduce liabilities. The movement from 2014 to 2015 was mainly due to the impairment write downs driven by the oil price environment.

· In 2015 a non-cash impairment charge of $203 million (post-tax) turned a pre impairment post-tax profit of $82 million into a post-tax loss of $121 million. A similar impairment charge ($173 million post-tax) was recorded in 2014. These impairments resulted from materially lower near term oil prices assumptions. In 2016 there has been no further significant change in the oil price environment, therefore 2016 shows a modest post-tax impairment of $3m due to the cessation of production from the Causeway and Topaz fields.

2016 RESULTS OF OPERATIONS

REVENUE

Revenue decreased by $63.3 million in 2016 to $143.7 million (2015: $207.0 million) primarily as a consequence of an $11/bbl or 20% decrease in the pre-hedging realised oil price associated with the fall in Brent during the year, coupled with a 20% decrease in underlying sales volumes.

While produced volumes decreased by 23% in 2016 compared to 2015, sales volumes decreased to a slightly lesser extent due to lifting schedules, in particular, larger oil liftings from the Cook field in 2016. Sales volumes decreased overall in 2016 primarily due to the cessation of production from the Athena, Anglia and Causeway fields as well as reduced production on the Dons fields.

The reduction in the average realised price for the year was offset to a significant extent by realised oil and gas hedging gains of $25 per sales barrel of oil equivalent in the year, resulting in an $87.9 million gain on commodities being reported through Foreign Exchange and Financial Instruments (see below).

In terms of the average realised oil price for the year, there was a decrease to $44/bbl in 2016 (2015: $54/bbl) in line with the average price of Brent for the twelve months ended 31 December 2016 (2015: $52/bbl). 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 traded in line with Brent.

COST OF SALES

Cost of sales decreased in 2016 by approximately 37% to $145.9 million (2015: $232.7 million). This was attributable to decreases in operating costs, depletion, depreciation and amortisation ("DD&A") and an increase in the value of oil and gas inventory.

OPERATING EXPENDITURE

Reported operating costs decreased by 27% in the year to $78.2 million (2015: $106.5 million). Cost reductions were achieved across the portfolio, with the Cook, Pierce and Wytch Farm fields delivering the most significant savings. This continued focus on driving down costs resulted in a unit operating cost of $23/boe for 2016, representing a reduction of over 25% compared to the equivalent rate of $31/boe for 2015 and below the $30/boe level guided at the start of the year. This reduced rate incorporates a significant benefit (~$3/boe compared to 2015) relating to movements in the US$:GBP exchange rate, as underlying costs are primarily incurred in pounds sterling.

DD&A

The unit DD&A rate for the period decreased to $21/boe (2015: $27/boe), resulting in a total DD&A expense for the period of $70.5 million (2015: $120.2 million). This reduction in expense was due to a combination of lower production 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 $2.8 million was credited to cost of sales in 2016 (2015: charge of $6.0 million). This credit arose primarily as a result of an increase in inventory value arising from the increase in underlying Brent prices between the end of 2015 and 2016, partially offset by an overlift in the year.

In 2016 less barrels of oil were produced (3,103 kbbls) than sold (3,188 kbbls), predominantly due to the lifting of the historic build-up of inventory on the Cook field, partly offset by production exceeding liftings on the Pierce field.

ADMINISTRATION EXPENSES AND EXPLORATION & EVALUATION EXPENSES

Administration expenses reduced through on-going cost saving measures

ADMINISTRATION EXPENSES

Total administration expenses were reduced by 46% to $5.4 million in 2016 (2015: $9.9 million). This was largely attributable to the cost savings initiatives that have been implemented within the lower oil price environment, as well as the absence of Norwegian expenses following the sale of Norwegian operations in July 2015. Costs incurred in the year reflect further reductions in contractor rates and a decrease in both employee and contractor numbers from 2015.

E&E EXPENSES

A minor write off of E&E assets was made in the year relating to non-commercial prospects. The 2015 write off relates primarily to the drilling of the unsuccessful Snømus exploration well in Norway, the costs for which were paid for by MOL Plc as part of the divestment of the Norwegian business during that year.

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS

FOREIGN EXCHANGE

While the majority of the Company's revenue is US dollar denominated, expenditures are predominantly incurred in pounds sterling (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 2016, a foreign exchange gain of $4.3 million was recorded (2015: $1.7 million loss). This was driven by the GBP:USD exchange rate moving from 1.48 at 1 January 2016 to 1.23 at 31 December 2016, with fluctuations throughout the year of between 1.22 and 1.48.

FINANCIAL INSTRUMENTS

The Company recorded an overall loss of $40.4 million on financial instruments for the year ended 31 December 2016 (2015: $155.0 million gain).

A $78.9 million realised gain was made in 2016. This comprised a $48.9 million gain on oil hedges maturing during the year (at an average exercise price of $64/bbl compared to an average Brent price of $44/bbl) and an $39.0 million gain on gas hedges (at an average price of 62p/therm compared to an average NBP price of 34p/therm), partially offset by a $8.8 million loss on foreign exchange and interest rate instruments. The total realised gain of $78.9 million in the period was offset by a $119.3 million negative revaluation of instruments as at 31 December 2016. This resulted from a negative revaluation of oil hedges of $65.1 million and gas hedges of $54.2 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 $65.1 million negative revaluation of oil hedges was due to the realisation of hedged oil volumes during the year (i.e. the transfer of previously unrealised gains to realised gain), combined with a downward revaluation of the remaining oil hedges at year end 2016 due to a strengthening of the oil forward curve. The $54.2 million negative revaluation of gas hedges arises in the same way, being a combination of realisations during the year and a negative revaluation of the remaining gas hedges at the year end due to a small increase in the gas forward curve.

As of 31 December 2016, the Company's commodity hedges were valued at $7.2 million, $3.6 million for oil hedges and $3.6 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 $36.6 million in 2016 (2015: $40.3 million). This reduction is primarily attributable to the decrease in RBL bank interest resulting from the deleveraging of the business over the last eighteen months, with drawn bank debt having fallen from $377 million at 31 December 2015 to $325 million at 31 December 2016. All other finance costs have remained relatively stable year on year.

TAXATION

No UK tax anticipated to be payable within the next 5 years

A tax credit of $29.9 million was recognised in the year ended 31 December 2016 (2015: $205.4 million credit). This comprises a charge relating to rate changes of $58.0 million offset by a credit of $87.8 million. Significant components of the $87.8 million Corporation Tax ("CT") credit include a $44.7 million credit relating to the UK Ring Fence Expenditure Supplement and $25.7 million in respect of additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac. The tax benefit of these capital allowances continue to be received by Ithaca as the expenditure is incurred. In recognition of the benefit Ithaca receives from the additional capital allowances a payment is expected to be made to Petrofac 5 years after Stella first oil of a sum calculated at the prevailing tax rate applied to the relevant capital allowances, in accordance with the SPA. The relevant capital allowances are expected to be around $250 million and implies, assuming current tax rates, a payment of approximately $100 million. A related deferred tax asset is recorded at 31 December 2016 of $95.0million reflecting the expected future benefit of these additional capital allowances.

The rate change related charge of $58.0 million comprises the impact of rate changes on CT of $82.1 million offset by a credit of $24.2 million relating to PRT.

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.

Further, it was also announced in the UK Budget that the SCT rate would 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 was to reduce the net deferred tax assets by $70.9 million, coupled with the CT impact of the PRT rate change of $11.2 million, giving an overall rate change driven CT charge for 2016 of $82.1million.

Note that the 2015 comparative contains a charge of $40.3 million relating to the previous changes in the SCT and PRT rates enacted in Q1 2015.

CAPITAL INVESTMENTS

2016 capital investment programme primarily focused on GSA development activities

Capital additions in 2016 totalled $75.2 million, with the major component being additions to development and production ("D&P") assets.

Excluding capitalised interest costs, non-cash additions relating to decommissioning and Vorlich licence acquisition costs paid at completion of the various transactions, capital expenditure was approximately $63 million. This mainly related to activities on the GSA, including work carried out on the oil export pipeline committed to post issuance of original guidance of $50 million. As previously advised, although the majority of the oil export pipeline work was carried out in 2016 it will only become cash spend in the first half of 2017.

WORKING CAPITAL

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

As at 31 December 2016 Ithaca had a net working capital credit balance of $16.2 million, including an unrestricted cash balance of $27.2 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 period. 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 twelve month period to 31 December 2016 mainly as a result of a reduction in the commodity hedging instrument asset values of $119.7 million noted above. The cash realised from the commodity hedges has been used to reduce debt.

CAPITAL RESOURCES

Over $110 million funding headroom at 31 December 2016 with net debt reduced to $598 million

DEBT FACILITIES

As at 31 December 2016 the Company has bank debt facilities totalling $535 million ($475 million senior RBL Facility and $60 million junior RBL), both with a maturity of September 2018, following the voluntary reduction in the size of the facilities from a total of $650 million during the year. Following the completion of the October 2016 RBL redetermination process, the debt capacity of these facilities was set at over $410 million. When combined with the $300 million senior unsecured notes, due July 2019, the Company has funding headroom of over $110 million as at 31 December 2016.

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, which are available on the Company's SEDAR profile at www.sedar.com, 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 2016

2016 CASHFLOW MOVEMENTS

During the twelve months ended 31 December 2016 there was a cash inflow from operating, investing and financing activities of approximately $15.7 million (2015 outflow of $7.8 million).

Cashflow from operations

Cash generated from operations was $146.8 million. Revenues from the producing asset portfolio were bolstered by the substantial hedging programme in place, while operating costs reduced by 27% period on period.

Cashflow from financing activities

Cash used in financing activities was $59.8 million, being primarily repayments of the debt facilities during the period combined with interest and bank charges on the RBL and Senior Notes.

Cashflow from investing activities

Cash used in investing activities was $95.5 million, primarily associated with further capital expenditure on the GSA development (including capitalised interest).

COMMITMENTS

The Company's commitments relate primarily to capital investment activities on the GSA, along with other on-going operational commitments across the portfolio. Rig commitments relate to the forthcoming Harrier development drilling campaign.

With the Stella field now in production, the Company's overall commitments are relatively modest and are forecast to be funded from the operating cashflows of the business.

In addition to the amounts above, in 2015 Ithaca entered into an agreement with Petrofac in respect of the FPF-1 Floating Production facility whereby Ithaca will pay Petrofac $13.7 million in respect of final payment on variations to the contract, with payment deferred until three and a half years after first production from the Stella field. A further payment to Petrofac of up to $34 million was initially to be made by Ithaca dependent on the timing of sail-away of the FPF-1. This further payment was revised to $17 million in Q3 2016. This payment will also be deferred until three and a half years after first production from the Stella field.

FINANCIAL INSTRUMENTS

All financial instruments are initially measured in the balance sheet at fair value. Subsequent measurement of the financial instruments is based on their classification. The Company has classified each financial instrument into one of these categories:

The classification of all financial instruments is the same at inception and at 31 December 2016.

COMMODITIES

The following table summarises the commodity hedges in place at 31 December 2016.

* Hedged with an average floor price of $46.50/bbl and a celling price of $60/bbl.

Q4 2016 FINANCIAL RESULTS

Average realised oil prices in Q4 2016 were $49/bbl or 9% higher than the corresponding period in 2015 as a result of a modest recovery in Brent prices. While this increase in oil price had an impact on sales revenue, the increase from $35.3 million in Q4 2015 to $41.3 million in Q4 2016 was also attributable to an increase in sales volumes. Sales volumes increased in the period primarily due to the timing of Cook liftings partly offset by reduced liftings from the Dons fields due to the Brent System shutdown in Q4 2016.

Gas volumes, which accounted for only approximately 3% of total revenue in the period, were up over 30% on the same period in 2015, although this was partly offset by slightly lower realised prices ($16/boe in Q4 2016 compared to $19/boe in Q4 2015).

Cost of sales decreased to $31.1 million in Q4 2016 (Q4 2015: $47.4 million) with significant reductions in operating costs and DD&A, offset by movements in oil and gas inventory.

The main drivers behind the decrease in operating costs from $23.1 million in Q4 2015 to $17.1 million in Q4 2016 were a combination of supply chain cost reductions across the portfolio coupled with reduced production and therefore lower absolute tariff costs. The above resulted in Q4 2016 operating costs of $22/boe compared to $24/boe in Q4 2015.

DD&A decreased significantly from $27.0 million in Q4 2015 to $11.4 million in Q4 2016. This reduction was mainly attributable to the impairment write downs booked at the end of 2015 as a consequence of the change in oil price environment, coupled with a change in field mix, with production primarily coming from the Cook, Pierce and Wytch Farm assets in Q4 2016. The blended rate for the quarter decreased from $26/boe in Q4 2015 to $15/boe in Q4 2016.

Movement in inventory was a charge of $2.6 million compared to a credit of $2.4 million in Q4 2015. As noted above, movements in oil inventory arise due to differences between barrels produced and sold combined with changes in the valuation of the barrels held as inventory. In Q4 2016 fewer barrels of oil were produced (693kbbl) than sold (814kbbl), mainly as a result of the timing of Cook field liftings, partially mitigated by the Pierce field liftings. This overlift was partly offset by the increase in value of oil inventory over the quarter as a result of the modest recovery in oil price. In Q4 2015 an excess of production volumes over sales volumes was partially offset by a significant reduction in the valuation of oil inventory to produce a credit of $2.4 million.

QUARTERLY RESULTS SUMMARY

1 Based on weighted average number of shares

The most significant factors to have affected the Company's profit before tax during the above quarters are fluctuations in underlying commodity prices and movement in production volumes. The Company has utilised commodity and foreign exchange hedging 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 commodity prices and exchange rates. In addition, the significant reduction in underlying commodity prices over the period has resulted in impairment write downs in Q4 2014 and Q4 2015. The tax charge/credit can also be volatile, for example due to the timing of recognition of losses.

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 December 2016 Ithaca had 413,099,042 common shares outstanding along with 24,413,139 options outstanding to employees and directors to acquire common shares.

(1) Represents the TSX close price (CAD$1.69) on 31 December 2016. US$:CAD$ 0.74 on 31 December 2016

Following the exercise of share options in the first quarter of the year, the number of common shares outstanding as of 23 March is 415,049,036.

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 December 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 31 December 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 December 2016, there were no changes in the Company's internal control over financial reporting that occurred during the year ended 31 December 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 December 2016, finance lease assets of $28.5 million and related liabilities of $30.2 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 2016 was $0.2 million (2015: $0.2 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 December 2016 the Company had loans receivable from FPF-1 Limited and FPU Services Limited, associates of the Company, for $59.9 million and $0.0 million, respectively (31 December 2015: $60.8 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

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

The Company's total net proved and probable reserves at 31 December 2016 were 76 MMboe (see "Licence Portfolio Activities"). These reserves were independently assessed by Sproule, a qualified reserves evaluator, as of December 31, 2016 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.

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 2016, (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, 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 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.

The Facilities are available on the Company's SEDAR profile at www.sedar.com. Also refer to "Capital resources - Debt Facilities" herein.

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 to Shell Trading International Ltd. Gas production is sold through contracts with 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 and the Department of Business, Energy & Industrial Strategy ("BEIS"). 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, with the exception of the Wytch Farm field for whjch the facilities are located onshore in the south of England, 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 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 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" 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;

· Delek's ability to complete the Offer;

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

· Expected future net debt and continued deleveraging;

· The anticipated Stella post start-up commissioning operations and production ramp up timings;

· 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 remaining work activities in respect of the GSA oil export pipeline and the timing thereof;

· 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 anticipated timing thereof;

· 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 and resources other than 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;

· Expected effects of fluctuations in foreign currency exchange rates; and,

· 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 and resources other than 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 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 22 March 2017. The 2016 results have been compared to the results of 2015. This MD&A should be read in conjunction with the Company's audited consolidated financial statements as at 31 December 2016 and 2015 together with the accompanying notes and Annual Information Form ("AIF") for the year ended 31 December 2016. 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.

To the Shareholders of Ithaca Energy Inc.

We have audited the accompanying consolidated financial statements of Ithaca Energy Inc. and its subsidiaries, which comprise the consolidated Statement of Financial Position as at 31 December 2016 and 31 December 2015, the Consolidated Statement of Income, the Consolidated Statement of Changes in Equity and Consolidated Statement of Cash Flow for the years then ended, and the related notes, which comprise a summary of significant accounting policies and other explanatory information.

Management's responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Ithaca Energy Inc. and its subsidiaries as at 31 December 2016 and 31 December 2015 and their financial performance and their cash flows for the years then ended in accordance with International Financial Reporting Standards.

Chartered Accountants

"PricewaterhouseCoopers LLP"

PricewaterhouseCoopers LLP

431 Union Street

Aberdeen

AB11 6DA

22 March 2017

Consolidated Statement of Income

For the year ended 31 December 2016

2016

2015

Note

US$'000

US$'000

Revenue

5

143,691

206,975

Operating costs

(78,219)

(106,468)

Movement in oil and gas inventory

(6,030)

(14,640)

Depletion, depreciation and amortisation

(120,230)

(167,378)

Cost of sales

(145,936)

(232,728)

Gross Loss

(2,245)

(25,753)

Exploration and evaluation expenses

10

(770)

(30,522)

Gain on asset disposal

2,913

26,600

(Loss) / Gain on financial instruments

27

(40,416)

155,326

Impairment of oil & gas assets

13

(5,543)

(386,679)

Impairment of goodwill

12

-

(13,604)

Total administrative expenses

6

(5,380)

(9,935)

Foreign exchange

4,319

(1,670)

Finance costs

7

(36,596)

(40,254)

Interest income

62

74

Loss Before Tax

(83,656)

(326,417)

Taxation

25

29,857

205,412

Loss for the year

(59,799)

(121,005)

Earnings per share (US$ per share)

Basic

24

(0.13)

(0.35)

Diluted

24

(0.13)

(0.35)

No separate statement of comprehensive income has been prepared as all such gains and losses have been incorporated in the consolidated statement of income above.

The accompanying notes on pages 8 to 26 are an integral part of the financial statements.

Consolidated Statement of Financial Position

as at 31 December 2016

Note

2016

US$'000

2015

US$'000

ASSETS

Current assets

Cash and cash equivalents

27,199

11,543

Accounts receivable

8

157,912

223,006

Deposits, prepaid expenses and other

667

743

Inventory

9

27,729

20,900

Derivative financial instruments

28

11,512

126,887

225,019

383,079

Non-current assets

Long-term receivable

30

59,922

61,052

Long-term inventory

9

8,438

7,908

Investment in associate

14

18,337

18,337

Exploration and evaluation assets

10

27,075

11,223

Property, plant & equipment

11

1,084,599

1,102,046

Deferred tax assets

25

383,663

355,726

Goodwill

12

123,510

123,510

1,705,544

1,679,802

Total assets

1,930,563

2,062,881

LIABILITIES AND EQUITY

Current liabilities

Trade and other payables

16

(236,928)

(275,907)

Exploration obligations

17

-

(4,000)

Contingent consideration

21

(4,000)

(4,000)

Derivative financial instruments

28

(4,329)

-

(245,257)

(283,907)

Non-current liabilities

Borrowings

15

(618,566)

(666,130)

Decommissioning liabilities

18

(206,933)

(226,915)

Other long term liabilities

19

(107,428)

(92,543)

Contingent consideration

21

(8,650)

-

Derivative financial instruments

28

-

(197)

(941,577)

(985,785)

Net Assets

743,729

793,189

Equity

Share capital

22

619,207

617,375

Share based payment reserve

23

25,185

22,678

Retained earnings

22

99,337

153,136

Total Equity

743,729

793,189

The financial statements were approved by the Board of Directors on 22 March 2017 and signed on its behalf by:

"Les Thomas"

Director

 "Alec Carstairs"

Director

For the year ended 31 December 2016

Share capital

Share based

payment

reserve

Retained

earnings

Total

Equity

US$'000

US$'000

US$'000

US$'000

Balance, 1 Jan 2015

551,632

19,234

274,141

845,007

Share based payment

-

3,444

 -

3,444

Shares issued

65,743

-

-

65,743

Loss for the year

 -

-

(121,005)

(121,005)

Balance, 31 December 2015

617,375

22,678

153,136

793,189

Balance, 1 Jan 2016

617,375

22,678

153,136

 793,189

Share based payment

-

3,058

-

3,058

Shares issued

1,832

(551)