IAE.L Regulatory News (IAE)

HIGHLIGHTS FIRST QUARTER 2017

Solid cashflow generation during the quarter

· Average production of 9,337 boepd (Q1 2016: 8,997 boepd)

· Unit operating expenditure reduced to $21/boe, down from $23/boe average rate in 2016

· Cashflow from operations of $30 million, resulting in a netback of $36/boe

· Earnings of $11 million (Q1 2016: $18 million loss)

· Downside commodity price hedging in place to mid-2018 - 6,800 boepd at an average floor of $49/boe from 1 April 2017

· Net debt of $614 million at 31 March 2017, up slightly on the year-end position of $598 million primarily as a result of working capital movements

First production from Stella field achieved mid-February 2017

· Stella field started up mid-February 2017 - producing at constrained rates to minimise gas flaring until gas processing systems fully available

· Commissioning of gas export compressors well advanced - one export train fully commissioned and the second materially completed

· Initial gas exports to the CATS pipeline system delivered with the first export compressor in April 2017 - gas exports currently temporarily suspended until later this month while mechanical repairs are completed on the FPF-1 sea water lift pumps that are required for gas system cooling

· Once both gas export compressors are fully operational, Stella remains forecast to add approximately 16,000 boepd net initial annualised production to the production portfolio

· Average full year 2017 production is forecast to be in the range of 18,000 to 19,000 boepd, reflecting the expected schedule for the step-up in Stella production rates

GSA development activities progressing to plan

· Harrier field development programme commenced - development well drilling in progress with start-up of production expected in the second half of 2018

· Good progress continues to be made on the FPF-1 modifications required to enable the switch from oil tanker loading to pipeline export in the second half of 2017

· Vorlich development planning on-going - identification of the optimal development solution and preparation for submission of a field development plan

· Additional 25% interest in the Ithaca-operated Austen discovery acquired from Premier Oil

Delek share tender offer completed - compulsory acquisition announced

· 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

· The offer was accepted by holders of 318,833,909 common shares resulting in Delek owning 94.2% of the issued and outstanding shares of the Company, including the shares it owned prior to announcement of the transaction

· Delek has announced it intends to carry out a compulsory acquisition of the remaining shares for the same cash consideration as the offer

SUMMARY STATEMENT OF INCOME

(1) Average realised price before hedging

(2) Revenue net of stock movements

(3) Figures shown net of Stella related returns and costs from investment in associate

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

Delek share tender offer completed - compulsory acquisition announced

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 for C$1.95 per share (the "Offer"). The Offer was made by DKL Investments Limited (the "Offeror"), an affiliate of Delek and Ithaca's largest shareholder at the time the Offer was announced.

On 20 April 2017 the conditions of the Offer were satisfied, with the Offer being accepted by holders of 241,293,465 of the issued and outstanding common shares of the Company. As required by securities laws, the Offer was subsequently extended until 3 May 2017, following which holders of a further 77,540,444 common shares were tendered. Consequently, upon completion of the Offer, the Offeror became the owner of 400,699,334 common shares, including the shares already owned by the Offeror prior to announcement of the takeover, representing 94.2% of the issued and outstanding shares of the Company.

Following completion of the Offer, Delek has subsequently notified the Company of its intention to carry out a compulsory acquisition by the Offeror of all the remaining issued and outstanding common shares of Ithaca not currently owned by the Offeror for the same cash consideration as the Offer under and subject to the Business Corporations Act (Alberta). As a consequence, the Company will be seeking to cancel its admission to trading on the AIM market of the London Stock Exchange and to voluntarily delist from the TSX following completion of the compulsory acquisition.

Refinanced RBL with extended tenor to be established in Summer 2017

DEBT FACILITIES

As at 31 March 2017, the Company's available RBL borrowing capacity is over $410 million. When combined with its existing $300 million senior unsecured notes, the business has a total debt capacity of over $710 million. Consequently, the Company maintains approximately $100 million of funding headroom when compared to net debt at the end of Q1 2017 of $614 million.

Ithaca's existing bank debt facilities and senior notes have maturities in late 2018 and mid-2019. During 2017 the Company will assess the options to refinance these credit facilities and the associated debt maturity profiles in order to ensure that they are appropriately aligned with the funding requirements of the business.

Additional interest acquired in the Ithaca-operated Austen discovery

Austen Licence

In May 2017 the Company entered into a sales and purchase agreement with Premier Oil E&P UK Limited to acquire its 25% interest in licence P1823 (Block 30/13b) for a nominal consideration. The licence contains the Ithaca-operated Austen discovery. The transaction, which is effective as of 1 January 2017 and expected to complete in the second half of 2017, will result in the Company being the sole owner of the licence.

The Austen discovery is located approximately 30 kilometres south-east of the GSA hub. It 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-10Z that was drilled in 2012 by the previous licence operator ENGIE E&P UK Limited. Further subsurface and development engineering studies are on-going in order to advance the preparation of a Field Development Plan for approval prior to January 2019.

Based on the results of the end-2016 independent reserves evaluation completed by Sproule International Limited in accordance with Canadian Oil and Gas Evaluation Handbook pursuant to NI 51-101 - Standards of Reserves Disclosure for Oil and Gas Activities, the acquisition adds approximately 2.5 million barrels of oil equivalent to the Company's proven and probable reserves base.

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 first hydrocarbons from the Stella field in mid-February 2017, operational activities on the FPF-1 have been centred on completion of the dynamic commissioning programme required on the gas processing systems on the vessel. During this programme, oil production continues to be maintained at constrained rates in order to minimise gas flaring. The oil processing facilities on the FPF-1 have been performing well and an initial cargo of approximately 235,000 barrels of oil was exported via shuttle tanker from the field in April 2017. Oil production to date from the field has averaged approximately 1,900 boepd net to Ithaca.

Dynamic commissioning activities on the gas processing facilities are now well advanced. The first of the two gas export compressors has been fully commissioned, with initial gas exports into the CATS pipeline system achieved in late April 2017, and commissioning of the second export compressor has also been materially completed. Gas exports have temporarily been suspended until replacement of the drive motors on the FPF-1 sea water lift pumps that provide cooling for the gas processing systems has been completed. As a consequence, it is forecast that gas exports from the first compressor will recommence later this month, stepping up to full production rates in early June 2017 once commissioning of the second export compressor is completed.

Once both gas export compressors are fully operational, Stella remains forecast to add approximately 16,000 boepd net initial annualised production to the Company's asset portfolio.

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

Good progress continues to be made on the required FPF-1 modifications to enable the switch from oil tanker loading to pipeline exports via the Norpipe system during 2017. All the main items of equipment required to be installed on the FPF-1 have now been transferred on to the vessel and work is progressing to plan on installation of the pipeline export pumps. Upon completion of the necessary tie-ins to the existing facilities on the FPF-1, the final subsea connections that need to be undertaken immediately prior to the switchover from shuttle tanker to pipeline export will be completed by Technip. This will involve a planned shutdown of production on the FPF-1 in the second half of 2017.

The opportunity to switch from tanker loading to pipeline export was secured in 2016, when access to the Norpipe system was secured through execution of a fast-track offshore work programme to make a connection to the system. This move will significantly reduce the fixed operating costs of the GSA facilities and enhance operational uptime and enable improved reserves recovery from the fields served by the FPF-1 production hub.

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 commenced in Q2 2017, beginning 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 development programme commenced in April 2017 when the ENSCO 122 heavy duty jack-up rig arrived on location for drilling of the planned multilateral well into the two Harrier reservoir formations. The drilling programme is scheduled to be completed in the second half of 2017, with the associated subsea infrastructure installation activities planned for summer 2018. The Harrier well is to be 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 start-up of production from the field is anticipated in the second half of 2018.

Vorlich development planning activities on-going

VORLICH DEVELOPMENT

Following the various transactions completed in 2016 to acquire an approximately 33% working interest in the BP-operated Vorlich discovery, work is progressing on the various studies and commercial negotiations required to identify the optimal development solution for the discovery. Completion of this work will enable a field development plan to be prepared and submitted to the UK Oil and Gas Authority for formal approval.

PRODUCTION & OPERATIONS

2017 PRODUCTION

Production in the first quarter of 2017 averaged 9,337 boepd (Q1 2016: 8,997 boepd). This represented a 4% increase on production in Q1 2016 predominantly due to higher volumes from the Pierce field, along with a modest contribution from the Stella field, offsetting natural decline on the Dons area fields.

Average production in 2017 is forecast to be in the range of 18,000 to 19,000 boepd (80% oil), reflecting the schedule for the step-up in Stella production rates and the other previously noted planned maintenance shutdowns scheduled for the asset portfolio during the year.

COMMODITY HEDGING

Additional hedging put in place - commodity price protection established for 6,800 boepd to June 2018

As part of the financial and risk management strategy of the business, 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 the Company's debt finance facilities.

In Q1 2017, the Company benefitted from realised commodity hedging gains in the period of $7.9 million, equating to an additional $10 of revenue per sales barrel of oil equivalent in the quarter.

As of 1 April 2017 the Company has 6,800 boepd (90% oil) hedged at an average floor price of $49/boe for the 15 months to 30 June 2018. Full commodity price upside exposure has been retained on 65% 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 April 2017, these hedges were valued at $5.0 million.

OPERATING EXPENDITURE

Net unit operating costs for Q1 2017 of $21/boe - forecast to fall to ~$18/boe for the full year

Net unit operating costs for Q1 2017 were $21/boe. This represents a further reduction on the average rate of $23/boe delivered in 2016, resulting from continued downward pressure on operating costs across the portfolio and the benefit of a modest contribution during the quarter from lower cost Stella field production.

Forecast 2017 net 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

2017 capex estimated to be approximately $70M

Capital expenditure in 2017 is forecast to total approximately $70 million, of which approximately $8 million was incurred in Q1 2017. 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.

NET DEBT

Net debt forecast to reduce further in 2017 through increased cashflow generation from Stella field

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, increasing slightly to $614 million at 31 March 2017 due to working capital movements and the timing of initial sales receipts from Stella field production.

Net debt is forecast to reduce significantly over the course of 2017 as the operating cashflows of the business step up materially as a consequence of Stella production.

TRADING ENVIRONMENT

COMMODITY PRICES

Although the increase in Brent has had a positive impact on revenues in Q1 2017 relative to Q1 2016, it is worth noting that the oil price impact on the Company's results in Q1 2016 were materially mitigated by the significant hedging protection that was in place.

FOREIGN EXCHANGE RATES

Volatility in exchanges rates resulting from the UK's decision during 2016 to exit the European Union has 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 derived from US dollar denominated oil sales, while approximately 80% of costs are incurred in pounds sterling. Going forward, gas sales in pounds sterling will significantly reduce GBP:USD exchange rate exposure.

Q1 2017 RESULTS OF OPERATIONS

REVENUE

Revenue increased to $37.2 million in Q1 2017 (Q1 2016: $33.2 million) as a consequence of a $15/bbl or 42% increase in the realised oil price prior to taking into account hedging, partly offset by a 21% reduction in sales volumes.

Although production volumes increased in Q1 2017 compared to Q1 2016, sales volumes were significantly less due to lifting schedules. In particular on Cook there were no oil liftings made during the quarter, with oil production instead being held in inventory at 31 March 2017 (see Cost of Sales section below).

The realised oil price for the quarter increased from $36/bbl in Q1 2016 to $51/bbl in Q1 2017, in line with the increase in Brent for the comparative periods. This price was further improved by realised oil and gas hedging gains of $10 per sales barrel of oil equivalent in the quarter, resulting in a $7.9 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 2017 by approximately 32% to $29.9 million (Q1 2016: $44.1 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 10% in the quarter to $18.1 million (Q1 2016: $20.2 million). These operating costs include tariff payments made to a 49% owned associated company of Ithaca, FPF-1 Limited. The net unit operating cost of the business is calculated by netting off the payments which are received by Ithaca through its 49% ownership in the associated company. This net unit operating cost averaged $21 per boe in Q1 2017 ($25/boe in Q1 2016), and is forecast to further reduce during 2017 as Stella production ramps up.

DD&A

The unit DD&A rate for the quarter decreased to $17/boe (Q1 2016: $21/boe), resulting in a total DD&A expense for the period of $14.5 million (Q1 2016: $17.6 million). This reduction in expense was due primarily to a lower average DD&A/boe rate as a result of increased proven and probable ("2P") reserves associated with a number of key fields in the portfolio, partially offset by increased production.

MOVEMENT IN INVENTORY

An oil and gas inventory movement of $2.8 million was credited to cost of sales in Q1 2016 (Q1 2015: charge of $6.3 million). This credit arose primarily as a result of increased stock volumes due to lifting schedules in the quarter, partially offset by a reduction in value due to the fall in Brent from the year end.

ADMINISTRATION EXPENSES AND EXPLORATION & EVALUATION EXPENSES

Administration expense levels maintained through on-going monitoring

ADMINISTRATION EXPENSES

Total administrative expenses were reduced to $1.6 million in Q1 2017 (Q1 2016: $1.8 million). Underlying G&A costs are tightly managed, with the business continuing to benefit from the savings that can be secured in the current commodity price environment.

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

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 Q1 2017, a foreign exchange gain of $1.7 million was recorded (Q1 2016: $0.5 million gain). This was primarily driven by the settlement of pounds sterling invoices at a lower exchange rate than the GBP:USD rate on the date they were received.

FINANCIAL INSTRUMENTS

The Company recorded an overall gain of $5.7 million on financial instruments for the quarter ended 31 March 2017 (Q1 2016: $5.2 million gain).

A $7.9 million realised gain was made in Q1 2017. This comprised a $5.1 million gain on oil hedges maturing during the quarter (at an average exercise price of $59/bbl compared to an average Brent price of $54/bbl) and a $2.8 million gain on gas hedges (at an average price of 64p/therm compared to an average NBP price of 48p/therm. The total realised gain of $7.9 million in the period was offset by a $2.2 million negative revaluation of instruments as at 31 March 2017.

The $2.2 million negative revaluation of commodity hedges was due to the realisation of hedged oil and gas volumes during the quarter (i.e. the transfer of previously unrealised gains to realised gain), partly offset by an upward revaluation of the remaining hedges at 31 March 2017 due to a weakening of the oil forward curve.

As of 31 March 2017 the Company's commodity hedges were valued at $5.0 million based on valuations relative to the respective oil and gas forward curves, comprising $1.5 million for oil hedges and $3.5 million for gas hedges.

FINANCE COSTS

Reducing finance cost profile driven by decreasing net debt

Finance costs decreased to $8.6 million in Q1 2017 (Q1 2016: $9.2 million). This reduction is primarily attributable to the decrease in RBL bank charges resulting from the deleveraging of the business over the last eighteen months. All other finance costs have remained relatively stable quarter on quarter.

TAXATION

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

A tax credit of $6.5 million was recognised in the quarter ended 31 March 2017 (Q1 2016: $34.2 million credit). The key driver between the anticipated tax charge of $1.7 million, being 40% of profit before tax for the quarter, and the tax credit that has been recognised is a $9.2 million credit relating to the UK Ring Fence Expenditure Supplement, partly offset by a small charge in respect of adjustments to the additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac. In accordance with the Stella Sale and Purchase Agreement ("SPA"), Ithaca receives the right to claim a tax benefit for these capital allowances and the tax benefit of these 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 legal completion of the SPA, in accordance with its terms, of a sum calculated at the prevailing tax rate applied to the relevant capital allowances. 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 March 2017 of $93.5million reflecting the expected future benefit of these additional capital allowances.

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 was enacted in March 2016 and therefore the deferred PRT provision was fully released through the Q1 2016 results giving rise to a credit of $24.2 million.

It was also announced in the UK Budget on 16 March 2016 that the Supplementary Corporation Tax ("SCT") rate payable by oil and gas producers would be reduced from 20% to 10% with effect from 1 January 2016. This reduces the Company's future SCT charge accordingly. The impact of the 10% reduction in the SCT rate was not enacted until September 2016, meaning there is no impact on the Q1 2016 comparatives.

CAPITAL INVESTMENTS

2017 capital investment programme primarily focused on GSA development activities

Excluding capitalised interest costs, capital expenditure in the quarter was approximately $8.1 million, which mainly related to activities on the GSA.

WORKING CAPITAL

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

As at 31 March 2017 Ithaca had a net working capital credit balance of $14.8 million, including an unrestricted cash balance of $5.9 million held with BNP Paribas. Substantially all of the accounts receivable are current, being defined as less than 90 days. The Company regularly monitors all receivable balances outstanding in excess of 90 days. No credit loss has historically been experienced in the collection of accounts receivable.

Working capital movements are driven by the timing of receipts and payments of balances and fluctuate in any given 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 increased over the three month period to 31 March 2017 as a result of a positive cashflow from operations offset by repayment of borrowings in the quarter.

CAPITAL RESOURCES

Approximately $100 million funding headroom at 31 March 2017

DEBT FACILITIES

As at 31 March 2017 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. As at the same date, the debt capacity of these facilities was over $410 million. When combined with the $300 million senior unsecured notes, due July 2019, the Company has funding headroom of approximately $100 million as at the end of the quarter.

Both RBL facilities are based on conventional oil and gas industry borrowing base financing terms, neither of which have historic financial covenant tests, and are due to mature in late 2018. The Company's $300 million senior unsecured notes similarly have no historic financial covenant tests, nor do they have any financial maintenance covenant tests. The senior notes are due July 2019.

The Company's debt facilities are expected to be sufficient to ensure that adequate financial resources are available to cover anticipated future commitments when combined with existing cash balances and forecast cashflow from operations.

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.

Cashflow from operations

Cash generated from operating activities was $30.3 million. Revenues from the producing portfolio of assets were bolstered by the hedging programme in place combined with reduced operating costs.

Cashflow from financing activities

Cash used in financing activities was $12.0 million, being interest charges coupled with repayments of the debt facilities during the quarter.

Cashflow from investing activities

Cash used in investing activities was $18.3 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 on-going 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 shown in the table, 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 fully ramped up production is achieved 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 fully ramped up production is achieved 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 March 2017.

COMMODITIES

The following table summarises the commodity hedges in place at 31 March 2017.

* Hedged with an average floor price of $46.85/bbl and a celling price of $60/bbl.

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 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 March 2017 Ithaca had 415,885,700 common shares outstanding along with 21,536,481 options outstanding to employees and directors to acquire common shares.

(1) Represents the TSX close price (CAD$1.93) on 31 March 2017. US$:CAD$ 0.75 on 31 March 2017

Following completion of the Delek takeover offer on 3 May 2017 and the associated exercise of share options in accordance with the terms of the Offer, as of that date the issued and outstanding common shares of the Company totalled 425,338,568. All share options not exercised and tendered to the Offer have been surrendered and cancelled. Accordingly, the fully diluted common shares of the Company total 425,338,568 as of 3 May 2017.

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 2017, 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 March 2017, 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 2017, there were no changes in the Company's internal control over financial reporting that occurred during the quarter ended 31 March 2017 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 2017, finance lease assets of $28.1 million and related liabilities of $29.8 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 2017 was $0.0 million (Q1 2016: $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 2017 the Company had loans receivable from FPF-1 Limited and FPU Services Limited, associates of the Company, for $59.7 million and $0.0 million, respectively (31 March 2016: $60.5 million and $0.1 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 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;

· Completion of the proposed compulsory acquisition by the Offeror under the Business Corporations Act (Alberta);

· The proposed cancellation of admission to trading on the AIM market of the London Stock Exchange, the proposed voluntary delisting for the TSX;

· 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 15 May 2017. The Q1 2017 results have been compared to the results of the comparative period in 2016. This MD&A should be read in conjunction with the Company's unaudited consolidated financial statements as at 31 March 2017 and 2016 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.

Consolidated Statement of Income

For the three months ended 31 March 2017 and 2016

(unaudited)

2017

2016

Note

US$'000

US$'000

Revenue

5

37,239

33,250

Operating costs

(18,118)

(20,185)

Other

(115)

-

Movement in oil and gas inventory

2,795

(6,325)

Depletion, depreciation and amortisation

(14,472)

(17,608)

Cost of sales

(29,910)

(44,118)

Gross Profit /(Loss)

7,329

(10,868)

Exploration and evaluation expenses

10

(745)

(421)

Gain on financial instruments

25

5,706

5,179

Total administrative expenses

6

(1,645)

(1,769)

Foreign exchange

1,708

502

Finance costs

7

(8,624)

(9,173)

Interest income

409

29

Share of profit in associate

 38

-

Profit/(Loss) Before Tax

4,175

(16,521)

Taxation

23

6,516

34,233

Profit After Tax

10,691

17,712

Earnings per share (US$ per share)

Basic

22

0.03

0.04

Diluted

22

0.02

0.04

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 6 to 22 are an integral part of the financial statements.

Consolidated Statement of Financial Position

(unaudited)

Note

31 March

2017

US$'000

31 December

2016

US$'000

ASSETS

Current assets

Cash and cash equivalents

5,870

27,199

Accounts receivable

8

135,105

157,912

Deposits, prepaid expenses and other

1,142

667

Inventory

9

25,827

27,729

Derivative financial instruments

26

7,812

11,512

175,756

225,019

Non-current assets

Long-term receivable

28

60,157

59,922

Long-term inventory

9

8,438

8,438

Investment in associate

13

18,375

18,337

Exploration and evaluation assets

10

28,150

27,075

Property, plant & equipment

11

1,081,769

1,084,599

Deferred tax assets

390,179

383,663

Goodwill

12

123,510

123,510

1,710,578

1,705,544

Total assets

1,886,334

1,930,563

LIABILITIES AND EQUITY

Current liabilities

Trade and other payables

15

(187,768)

(236,928)

Contingent consideration

19

-

(4,000)

Derivative financial instruments

26

(2,812)

(4,329)

(190,580)

(245,257)

Non-current liabilities

Borrowings

14

(614,585)

(618,566)

Decommissioning liabilities

16

(208,434)

(206,933)

Other long term liabilities

17

(107,853)

(107,428)

Contingent consideration

19

(8,650)

(8,650)

(939,522)

(941,577)

Net Assets

756,232

743,729

Equity

Share capital

20

621,345

619,207

Share based payment reserve

21

24,859

25,185

Retained earnings

110,028

99,337

Total Equity

756,232

743,729

The financial statements were approved by the Board of Directors on 12 May 2017 and signed on its behalf by:

"Les Thomas"

Director

 "Alec Carstairs"

Director

(unaudited)

Share capital

Share based

payment

reserve

Retained

earnings

Total

Equity

US$'000

US$'000

US$'000

US$'000

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

-

170,848

811,669

Balance, 1 Jan 2017

619,207

25,185

99,337

743,729

Share based payment

-

283

-

283

Shares issued

2,138

(609)

-

1,529

Profit for the period

-

-

10,691

10,691

Balance, 31 March 2017

621,345

24,859

110,028

756,232

For the three months ended 31 March 2017 and 2016

(unaudited)