2017 HIGHLIGHTS MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2017

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1 2017 HIGHLIGHTS Solid cashflow generation driven by increasing production and reduced unit operating costs Average production of 13,909 barrels of oil equivalent per day ( boepd ) (2016: 9,310 boepd) Average unit operating expenditure reduced to $19/boe 1, down from $23/boe in 2016 Cashflow from operations of $146 million 1 (2016: $147 million), equating to $29/boe 59% increase in underlying unit cashflow generation pre hedging cashflow from operations up from $17/boe in 2016 to $27/boe in 2017 Underlying earnings of $17 million after adjusting for one off impairments ($24.0million post tax) and non cash mark to market revaluation of hedges ($19.3 million post tax) Downside commodity price hedging in place to mid ,700 barrels of oil per day ( bopd ) hedged at an average of $57/bbl and 2,100 boepd gas hedged at 46p/therm Net debt of $605 million at 31 December 2017 increased cashflow generation is forecast to deliver accelerated deleveraging of the business in 2018 Proved and probable reserves at 31 December 2017 of 72 million barrels of oil equivalent ( MMboe ) 2, as independently evaluated by Sproule International Limited ( Sproule ) 3 reserves unchanged after adjusting for 2017 production Rising production driven by increased Stella volumes and Harrier start up Forecast 2018 production of approximately 15,000 boepd, reflecting divestment of the Wytch Farm field, the anticipated start up of the Harrier field in mid 2018 and planned maintenance shutdowns being undertaken during the year Production in the first quarter of 2018 is forecast to be approximately 18,000 boepd 4, reflecting strong operational uptime performance across the portfolio 2018 unit operating expenditure forecast to average approximately $19/boe 1 General and Administration (G&A ) expenses continue to be tightly managed at approximately $1/boe Net debt at 31 March 2018 forecast to reduce to approximately $560 million taking into account the proceeds of the Wytch Farm divestment, which is anticipated to complete by end March 2018 Refinancing of the Company s debt facilities and associated maturity profiles anticipated in 2018 GSA hub and spoke strategy progressing to plan Greater Stella Area ( GSA ) production hub fully operational switch from tanker loading to oil pipeline export completed and strong FPF 1 operational uptime performance being achieved Maximising value of GSA infrastructure through execution of the hub and spoke strategy Harrier start up anticipated mid 2018 and Vorlich development sanctioned for start up in 2020 Ithaca established as a wholly owned subsidiary of Delek Takeover by Delek Group Limited ( Delek ) completed in June 2017 shares delisted from the Toronto Stock Exchange and the AIM market of the London Stock Exchange Ithaca represents a core component of Delek s strategy to grow its international E&P business strong shareholder with ambition to expand its North Sea business using the established platform and expertise of Ithaca Corporate strategy remains unchanged following the takeover focus on the delivery of lower risk North Sea production and development led growth and further expansion of the asset portfolio while maintaining a robust low cost capital structure (1) Unit costs and cashflows from operations are stated net of Stella related revenues and expenditures from investment in associate (2) The total proved and probable reserves include approximately 4.2 MMboe associated with the Wytch Farm field and associated licences as the divestment had not completed as of the 31 December 2017 effective date of the reserves evaluation (3) Year end independent reserves evaluation has been performed by Sproule, a qualified reserves evaluator, in accordance with the Canadian Oil and Gas Evaluation Handbook pursuant to NI Standards of Reserves Disclosures for Oil and Gas Activities, which comply in all material respects with the definitions and guidelines set forth in the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers (4) Q production includes approximately 1,000 boepd from Wytch Farm, the divestment of which is expected to complete by the end of March

2 SUMMARY STATEMENT OF INCOME Average Production kboe/d Average Realised Oil Price (1) $/bbl Revenue (2) M$ Hedging Cash Gain (Loss) M$ Revenue (2) (After Hedging) M$ Opex (3) M$ (97.5) (78.2) Other M$ (2.4) - G&A - underlying M$ (4.2) (4.7) G&A Delek transaction costs M$ (5.4) - Foreign Exchange (4) M$ 3.7 (4.7) Cashflow from Operations M$ DD&A & Impairment M$ (166.8) (76.1) Non-Cash Hedging (Loss) M$ (32.2) (119.3) Gain on disposal of assets M$ Finance Costs M$ (50.1) (36.6) Other Non-Cash Costs M$ (3.3) 1.3 Taxation M$ Earnings M$ (26.2) (53.8) Cashflow Per Share $/Sh Earnings Per Share $/Sh. (0.06) (0.13) (1) Average realised price before hedging (2) Revenue net of stock movements (3) Figures shown net of Stella related returns and costs from investment in associate (4) Foreign exchange net of related realised hedging gains & losses SUMMARY BALANCE SHEET M$ 31 Dec Dec Cash & Equivalents Other Current Assets PP&E 1,120 1,112 Deferred Tax Asset Other Non-Current Assets Total Assets 2,015 1,931 Current Liabilities (322) (245) Borrowings (632) (619) Asset Retirement Obligations (191) (207) Other Non-Current Liabilities (150) (116) Total Liabilities (1,295) (1,187) Net Assets Share Capital Other Reserves - 25 Surplus Shareholders Equity

3 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. Execution of Ithaca s strategy is focused on the following core activities: Maximising production and cashflow from the existing asset base Delivery of lower risk, long term development led growth through the appraisal of undeveloped discoveries Maintaining capital discipline, financial strength and a clean balance sheet, supported by lower cost debt leverage Continuing to grow and diversify the cashflow base by securing new producing, development and appraisal assets through targeted acquisitions and licence round participation Ithaca is a wholly owned subsidiary of the Tel Aviv stock exchange listed Delek Group Limited (TASE:DLEKG / US ADR:DGRLY), Israel s leading integrated energy company. CORPORATE ACTIVITIES Recommended cash takeover by Delek completed in June 2017 Cessation of Canadian reporting issuer status Board of Directors reduced to match private company status Continuance of Company from Canada to Jersey planned New Executive team appointments DELEK TAKEOVER & SHARES DELISTING On 6 February 2017 it was announced that the Company had entered into a definitive support agreement with 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 DKL Investments Limited (the Offer ), a wholly owned subsidiary of Delek and Ithaca's largest shareholder prior to the announcement. Following completion of the initial share tendering period and subsequent compulsory acquisition, the takeover process was concluded in June 2017 and Ithaca became a wholly owned subsidiary of Delek. As a result, the Company s shares were delisted from the Toronto Stock Exchange ( TSX ) and the AIM market of the London Stock Exchange. CANADIAN REPORTING ISSUER STATUS Following delisting of the shares on the TSX, the Company obtained approval from the Canadian securities regulatory authorities to cease being a reporting issuer in all applicable Canadian jurisdictions. As a result, Ithaca is no longer required to file financial statements and other continuous disclosure documents with Canadian securities regulatory authorities. The Company will however continue to make disclosures as required under its $300 million senior unsecured notes. BOARD OF DIRECTORS Given Ithaca s status as a wholly owned subsidiary of Delek, the Company has reduced the size of the Board of Directors to more appropriately reflect the requirements of the business. Mr Ron Brenneman retired as a Non Executive Director in August 2017 and Messrs Jay Zammit, Alec Carstairs and Yossi Abu retired as Non Executive Directors in March The remaining directors of Ithaca are unchanged, with Mr Brad Hurtubise continuing as Non Executive Chairman, Mr Asi Bartfeld as a Non Executive Director and Mr Les Thomas as a Director and Chief Executive Officer of the Company. CONTINUANCE As part of the simplification of the corporate structure, the Company intends to seek regulatory approval to continue Ithaca Energy Inc. from Canada into Jersey and align the incorporation of the Company with that of its sole shareholder DKL Investments Limited (a wholly owned subsidiary of Delek). EXECUTIVE MANGEMENT CHANGES Mr Roy Buchan, Chief Operations Officer, will be leaving the Company in April 2018 and be replaced by Mr Jamie Airnes. Mr Airnes has over 20 years operational experience in the oil and gas industry, having held various technical and senior management positions in the North Sea and internationally for BP, Talisman, Woodside and Apache. Mr Airnes joined Ithaca Energy in 2011, with responsibility for the Company s drilling and well management operations and non operated assets portfolio. In addition Mr John Horsburgh will be taking on the new position of Chief Technical Officer, having been Ithaca s Subsurface Manager and Competent Person responsible for corporate reserves reporting. Prior to joining Ithaca in 2008, Mr Horsburgh worked for 10 years at Royal Dutch Shell where he held senior technical positions for various field development projects in the North Sea, Africa and the Middle East. 3

4 FINANCIAL STRATEGY Financial strategy unchanged following Delek acquisition retain flexible low cost capital structure The acquisition of Ithaca was a central part of Delek s strategy to diversify its oil and gas business internationally and establish an operated business focused on the North Sea. Prior to the acquisition Delek s upstream business had been almost exclusively located in the Eastern Mediterranean, where it produces approximately 25,000 boepd and has around 1,205 MMboe of 2P and 2C resources predominantly associated with two world class gas developments offshore Israel. Following an initial equity investment in 2015, completion of the takeover marked the culmination of an approximately $600 million investment in Ithaca. Ithaca s corporate strategy remains unchanged following the takeover, with the business continuing to focus on the delivery of lower risk North Sea production and development led growth. Alongside progressing its portfolio of organic growth opportunities, the Company is actively engaged in the identification and evaluation of potential high quality North Sea acquisitions that can enhance the scale of the business and enable the realisation of operational and financial synergies for the Company. Execution of this strategy is underpinned by Ithaca s growing and sustainable free cashflow profile, which is driven by high netback production from both established and new field start ups. This, coupled with the financial support of Delek, provides Ithaca with a strong platform from which to accelerate the growth objectives of the business while proactively managing and maintaining a prudent capital structure. The financial policy of the business remains focused on retaining a flexible capital structure, through a balanced blend of low cost secured and unsecured debt finance and maintenance of adequate liquidity headroom from cash and undrawn debt. No dividends are anticipated in the short to medium term and the Company is targeting a reduction in its net debt to EBITDAX leverage ratio to below 3.0x in the next twelve months. During 2018 the Company will assess the options to refinance its credit facilities and associated debt maturity profiles. PRODUCTION & OPERATIONS Material increase in production driven by startup of the Stella field in February 2017 Average production in 2017 was 13,909 boepd (~75% oil), reflecting a 49% increase on the previous year (2016: 9,310 boepd). This increase was driven by the start up of production from the Stella field in February 2017, with the full impact of the field being realised at the end of the second quarter once commissioning of the gas processing and export systems on the FPF 1 floating production facility had been completed and the field was ramped up to peak rates. Total production in the second half of the year was partially reduced as a consequence of planned maintenance shutdowns, notably on the Cook and Stella fields, with the latter shutdown being undertaken to enable the final FPF 1 oil export pipeline tie ins to be completed and the switchover from oil tanker loading to pipeline exports to take place. The base production portfolio performed well during Natural decline across the various fields was partially mitigated by solid operational uptime performance on the various host facilities, including a step change in uptime compared to the prior year from the floating production, storage and offloading ( FPSO ) vessel that serves the Pierce field. On the Stella field, the uptime performance of the FPF 1 has been strong since completion of the dynamic commissioning programme and the switchover to oil pipeline exports from the facility. Average operating efficiency over the last six months has been approximately 90%. This represents an important step forward for the overall GSA development plan, as execution of the hub and spoke strategy moves on from the start up of initial production to the tie back of satellite fields in order to sustain long term production and cashflow from the hub over the coming years OPERATIONS During 2018 the main operational programmes involve start up of the Harrier field and preparation for the drilling of a water injection well on the Cook field in Three well workovers are scheduled to be performed on the Pierce field, as part of a campaign to access incremental production from the existing well stock, and a number of routine production protection / enhancement chemical treatments are scheduled on wells in the Dons Area. Production volumes are forecast to be reduced predominantly in the third quarter of the year as a result of various planned maintenance shutdowns. These include an approximately 10 week shutdown on the Pierce field to complete routine life extension works on the FPSO serving the field and an approximately 4

5 3 week shutdown on the Dons Area fields. An approximately two week shutdown of the FPF 1 is also scheduled, driven by planned maintenance on the Central Area Transmission System ( CATS ) gas export system PRODUCTION Average production in 2018 is anticipated to be approximately 15,000 boepd (approximately 60% oil). This reflects divestment of the Wytch Farm field (completion anticipated end March 2018), the anticipated start up of the Harrier field in mid 2018, the programme of planned maintenance shutdowns during the year and sensitivities associated with the performance of those operational programmes. Taking into account year to date performance, production in the first quarter of 2018 is forecast to average approximately 18,000 boepd. The portfolio has performed consistently during the period, with no significant disruption to operations occurring during the main months of the North Sea winter season. GREATER STELLA AREA DEVELOPMENT ACTIVITIES GSA hub and spoke strategy Core central hub infrastructure investment completed switch made from oil tanker to pipeline exports Harrier field development progressing to plan production start up scheduled for mid 2018 Ithaca s focus in the Greater Stella Area ( GSA ) is centred on monetisation of the Company s existing portfolio of undeveloped discoveries that are located in the area. With start up of the Stella field in 2017, the Company has established a new production hub serviced by the Ithaca operated FPF 1 floating production facility, where initial oil and gas processing is undertaken for onward export to market. It is planned for further wells to be drilled and tied back to the FPF 1 on the wider GSA satellite portfolio over the coming years in order to maximise production and cashflow from the area. As with the addition of the Vorlich and Austen field interests in 2016, the Company is also focused on expanding the satellite feeder field portfolio in order to drive additional value from the hub. GSA INFRASTRUCTURE The GSA infrastructure has been set up as a flexible oil and gas production and processing hub in the Central North Sea area of the UK Continental Shelf. The FPF 1 floating production facility, which lies at the centre of the infrastructure, has been extensively modified and equipped with new facilities that provide significant operational flexibility for managing the processing of multiple feeder fields. Oil and gas production from the facility is exported to market in the UK via two major pipeline systems, the Norpipe and CATS pipelines, respectively. The connection to the Norpipe system was made in September 2017, enabling the switchover from the export of oil production by offshore tanker loading, and marked completion of the final investment in the central infrastructure of the FPF 1 production hub. This move significantly reduces the fixed operating costs of the hub facilities, enhances operational uptime and enables improved reserves recovery from the fields the FPF 1 serves. HARRIER START UP IN 2018 In line with the Company s strategy for building out the GSA production hub, production from the Harrier field is schedule to start up in mid The development programme commenced in April 2017 when the ENSCO 122 heavy duty jack up rig arrived on location for drilling of a dual lateral well into the two Harrier reservoir formations. The drilling programme was completed in September 2017, with the well being suspended ready for connection to the subsea infrastructure through which the field will be produced. The Harrier field is being tied back via a 7.5 kilometre pipe in pipe flowline to an existing slot on the Stella main drill centre manifold for onward export and processing of production on the FPF 1. Fabrication of the subsea infrastructure has progressed well and is nearing completion. It is anticipated that the equipment will be ready for loading on to the installation vessels in Evanton, Scotland, in the second quarter of The total cost of the overall development is expected to be approximately $65 million net to Ithaca. Based on the net proven and probable reserves of the field, this represents a capital investment cost of approximately $5/boe. Vorlich development sanctioned and scheduled for start up in 2020 VORLICH DEVELOPMENT SANCTION Following completion of the studies and commercial negotiations required to finalise the optimal development solution for the BP operated Vorlich discovery (34% Ithaca working interest), the joint venture formally selected the FPF 1 as the host facility for the field in late The investment programme has now been sanctioned by the partners and work is underway to deliver start up of production from the field in Submission of the formal Field Development Plan for the approval of 5

6 the UK Oil and Gas Authority is scheduled for mid Vorlich is an oil and gas condensate field that was discovered and appraised by BP in The field is estimated to contain gross proven and probable reserves of approximately 25 MMboe and is to be developed via two subsea wells, which are expected to be drilled in 2019, tied back to the FPF 1 via an approximately 9 kilometre pipe in pipe flowline to a new dedicated flexible riser and umbilical connecting the subsea infrastructure to the vessel. Work has recently commenced on the procurement and fabrication of the subsea infrastructure, following award of the engineering procurement and installation contract to Technip UK Limited. Production from the field will undergo initial processing on the FPF 1 using a dedicated first stage separation train on the vessel. These facilities were installed during the modification of the FPF 1 at minimal incremental cost in order to provide such processing flexibility for satellite fields. Certain minor modifications will be made to these facilities prior to start up of the field in order to maximise liquids production from the field and enhance the overall value of the development. The total cost of the overall development is expected to be approximately $100 million net to Ithaca. Based on the net proven and probable reserves of the field, this represents a capital investment cost of approximately $12/boe. In addition to the value associated with Ithaca s interest in the Vorlich field, the Company will benefit from the income received by the Stella field joint venture (54.66% Ithaca working interest) for the provision of transportation, processing and operating services by the FPF 1. Development planning activities progressing across the GSA satellite portfolio FUTURE SATELLITES The GSA satellite portfolio includes the Hurricane and Austen undeveloped discoveries. Work is progressing on the subsurface and development engineering studies required to advance preparation of Field Development Plans for these fields. Additionally, a number of applications were made as part of the 30 th UK Licensing Round in November 2017 in order to further enhance the GSA portfolio. It is anticipated that the results of the Licencing Round will be announced by the Oil and Gas Authority in the coming months. LICENCE PORTFOLIO ACTIVITIES Wytch Farm divestment completion anticipated by end March 2018 Austen working interest increased to 100% in 2017 WYTCH FARM DIVESTMENT As announced on 18 January 2018, Ithaca entered into an agreement for the sale of its interests in Licences PL089, P534 and PEDL 328, which contain the onshore Wytch Farm field, to Verus Petroleum SNS Limited ( Verus ) for a cash consideration of $53 million. The transaction was subject to the preemption rights of existing joint venture partners and Ithaca subsequently received notification from Perenco UK Limited ( Perenco ) of its intention to exercise those rights. The Company has therefore entered into a sale and purchase agreement with Perenco, on materially the same terms and conditions as were previously agreed with Verus. It is expected that the transaction will complete in early April 2018, with the proceeds of the sale being used to partly repay the Company s existing bank debt facilities. AUSTEN In May 2017 the Company entered into a sales and purchase agreement ( SPA ) with Premier Oil E&P UK Limited to acquire its 25% interest in licence P1823 (Block 30/13b), which contains the Ithacaoperated Austen discovery, for a nominal consideration. The transaction was completed in June 2017, resulting in the Company becoming 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 NON CORE LICENCE DIVESTMENT In June 2017 an SPA was executed with Zennor North Sea Limited in June 2017 to divest licence P2182 (Blocks 22/15a (All) and 23/11d (All), containing the non core Banks / Esperanza undeveloped discoveries, for a minimal consideration. 6

7 YEAR-END 2017 RESERVES The Company s reserves as of 31 December 2017 have been independently evaluated by Sproule, a qualified reserves evaluator, in accordance with the Canadian Oil and Gas Evaluation Handbook pursuant to NI Standards of Reserves Disclosures for Oil and Gas Activities, which comply in all material respects with the definitions and guidelines set forth in the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers. The report summarising the Sproule reserves evaluation is available on the Company s website ( Total proved and probable ( 2P ) reserves as at 31 December 2017 are estimated to be 72 MMboe The 2P reserves include approximately 4.2 MMboe associated with the Wytch Farm field and associated licences as the divestment to Perenco had not completed as of the effective date of the reserves evaluation (the transaction is anticipated to complete by the end of March 2018). Year end 2P reserves are unchanged compared to year end 2016 after adjusting for 2017 production. The main revisions at year end related to increases in the reserves associated with the Cook, Vorlich and Austen fields (the latter resulting from the acquisition of an additional 25% working interest in 2017) offsetting a reduction in the Stella reserves as a consequence of the higher producing gas oil ratio observed following start up of the field. As of 31 December 2017, the post tax net present value of the 2P reserves discounted at 10% ( NPV 10 ) was estimated by Sproule to be $1,370 million. This is based on forecast Brent prices of $58/bbl in 2018 rising to $67/bbl in 2019 and approximately $85/bbl in The Company has a balanced producing and development asset reserve base, with 30 MMboe (~45%) of total 2P reserves associated with producing assets (excluding Wytch Farm reserves). The development asset reserves are almost exclusively associated with the GSA satellite fields. 7

8 OPERATING & FINANCIAL OUTLOOK ~15,000 boepd 2018 production guidance Additional hedging put in place commodity price protection established for 7,800 boepd to June net unit operating cost ~$19/boe ~$60M 2018 capital investment programme PRODUCTION Average production in 2018 is anticipated to be approximately 15,000 boepd (approximately 60% oil). This reflects divestment of the Wytch Farm field, the anticipated start up of the Harrier field in mid 2018, the programme of planned maintenance shutdowns during the year and sensitivities associated with the performance of those operational programmes. COMMODITY HEDGING As part of the financial and risk management strategy of the business, the Company actively seeks to maintain a balanced commodity hedging position. In summary, downside commodity price protection is in place for the 18 months to 30 June ,700 bopd of oil production has been hedged via a combination of swaps and put options over the period at an average price floor of $57/bbl. Full price upside exposure has been retained on approximately 40% of the hedged oil volumes. In terms of gas, 11 million therms of production (approximately 2,100 boepd) has been hedged using swaps with a floor price of 46p/therm being established. OPERATING EXPENDITURE As part of managing and minimising the impact of the abrupt decline in oil prices since the second half of 2014, the Company and its partners undertook various important steps to reset the cost base and enhance the cashflows of the business. This has resulted in unit operating costs falling from an average of $31/boe in 2015 to $23/boe in 2016, with a further decrease to $19/boe secured in 2017 (net of the Company s Stella related revenues and expenditure from its investment in associate) following the introduction of lower cost Stella field production into the portfolio from February Unit operating costs are forecast to remain at approximately $19/boe in Further reductions are expected in future years as the contribution of the GSA satellite fields continues to increase within the overall portfolio. CAPITAL EXPENDITURE As previously highlighted, the Company forecasts an average underlying capital expenditure of $10 25 million per annum on its producing asset portfolio. This primarily relates to low cost production enhancement activities. In addition to this, the Company has a range of further investment opportunities within its existing portfolio and the flexibility to tailor its capital programme to align with the economic outlook at the time. It is anticipated that the average annual capital expenditure required to develop these opportunities will be between $25 75 million. In 2017 the capital investment programme totalled $76 million, with activities primarily focused on completion of the GSA oil export pipeline works and Harrier development drilling programme. The 2018 capital programme is forecast to total approximately $60 million. The two key components of this relate to completion of the subsea infrastructure installation works on the Harrier field development and progression of the Vorlich subsea infrastructure procurement and fabrication programme. In terms of base portfolio activities, three well workovers are to be performed on the Pierce field as part of accessing incremental oil volumes and a number of production protection / enhancement chemical treatments are scheduled on wells in the Dons Area. Net debt forecast to reduce to $560M at 31 March 2018 NET DEBT Net debt at 31 December 2017 of $605 million was materially unchanged from the position at the end of In 2018 the business is set to resume the deleveraging trend of earlier years, driven by increased operating cashflows and the proceeds of the Wytch Farm divestment. The divestment is anticipated to complete by the end of March 2018 and as such, net debt at the end of the first quarter of 2018 is forecast to be approximately $560 million. 8

9 TRADING ENVIRONMENT COMMODITY PRICES Brent & NBP gas prices Jan Dec Annual Average Prices Brent Benchmark $/bbl NBP Gas Price p/therm / $MMbtu 45 / / 4.76 Following the significant fall in crude oil prices in , the Brent benchmark price been on a generally positive trajectory since the low point in January Although the increase in Brent has had a positive impact on revenues in 2017 relative to 2016, the Company s results in 2016 were more materially enhanced by higher priced oil hedges in place during that period. Subject to customary seasonal fluctuations, the UK NBP gas price has also been on a generally upward trajectory since January Following the start up of production from Stella in February 2017, the proportion of revenues derived from gas production has substantially increased, accounting for 17% of total revenue for the twelve months ended 31 December 2017 (3% in 2016). FOREIGN EXCHANGE RATES GBP:USD Jan Dec GBP : USD average GBP : USD period end spot Volatility in exchanges rates resulting from the UK s decision during 2016 to exit the European Union saw a devaluation of the pound sterling versus the US dollar which, in turn, had a positive impact on the financial results. Prior to the introduction of gas sales from the Stella field the majority of the Company s revenue was derived from US dollar denominated oil sales, while approximately 80% of costs were incurred in pounds sterling. Going forward, gas sales in pounds sterling are expected to significantly reduce the Company s exposure to fluctuations in the GBP:USD exchange rate. 9

10 2017 RESULTS OF OPERATIONS REVENUE Revenue $ Oil Sales 188, ,749 Gas Sales 41,521 4,269 NGL Sales 11, Other income Total 242, ,691 Total revenue increased by $98.7 million in 2017 to $242.4 million (2016: $143.7 million) as a result of an approximately 49% increase in year on year production. With the start up of production from the Stella field, the increased revenues come from all product streams, oil, gas and NGLs. OIL Oil revenues rose as a consequence of a $9/bbl or 21% increase in the pre hedging realised oil price associated with the rise in Brent during the year, coupled with a 12% increase in underlying sales volumes. Average realised oil prices increased to $53/bbl in 2017 from $44/bbl in This is in line with the average Brent price movement to $54/bbl for 2017 compared with $44/bbl for Post hedging, the average realised oil price for 2017 increased by a further $1/bbl to $54/bbl. This compares to an oil hedging gain of $15/bbl in While realised oil prices for each of the fields in the Company s portfolio do not strictly follow Brent prices, 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. As noted above produced oil volumes increased approximately 14% in the year predominantly due to the addition of Stella production and increased volumes from the Pierce field. This increase in production in turn led to larger liftings from both the Stella and Pierce fields. See movement in inventory section below for further details. GAS & NGLS Gas and NGL revenues have both increased significantly from a combined $4.8 million in 2016 to $53.5 million in The start up of the Stella field has given rise to these significant gas and NGL revenues for the first time in Gas production from the Stella field is priced broadly in line with the NBP benchmark. COST OF SALES Operating Expenditure $ Operating Expenditure 116,389 78,219 DD&A 126,867 70,521 Movement in Oil & Gas Inventory (1,316) (2,804) Other 2,415 - Total 244, ,936 Cost of sales increased in 2017 by approximately 67% to $244.4 million (2016: $145.9 million) predominantly due to increases in operating costs and Depreciation, Depletion and Amortisation ( DD&A ) expenses. OPERATING EXPENDITURE Operating costs increased by 49% in the period to $116.4 million (2016: $78.2 million) primarily as a result of a corresponding 49% increase in total production, partially offset by a year on year reduction in net unit cost from $23/boe to $19/boe (net of the Company s Stella related revenues and expenditure from its investment in associate), reflecting the lower cost Stella field production contribution to the portfolio. 10

11 DD&A Total DD&A expense for the period was $126.9 million (2016: $70.5 million). This increase in expense was due primarily to the inclusion of production from the Stella field combined with a modest increase in the unit DD&A rate for the period from $21/boe to $25/boe. MOVEMENT IN INVENTORY An oil and gas inventory movement of $1.3 million was credited to cost of sales in 2017 (2016: credit of $2.8 million). In 2017 almost the same number of barrels of oil were produced (3,542 kbbls) as sold (3,556 kbbls), despite lifting versus production patterns varying significantly by field (in particular on Cook and Pierce). An increase in the value of oil inventory has resulted in a credit to the income statement, partly offset by the occurrence of a net overlift position in other hydrocarbons. Title for gas generally passes as the gas flows through the pipeline system, meaning there are no significant under or overlifts relating to gas sales. In contrast, Natural Gas Liquids ( NGL ) extracted from gas production during onshore processing tend to be lifted periodically. Consequently more NGL was sold than produced in 2017, resulting in an overlift balance. Movement in Operating Oil & Gas Inventory Oil kbbls Gas/NGL kboe Total kboe Opening inventory 384 (3) 381 Production 3,542 1,535 5,077 Liftings/sales (3,556) (1,568) (5,124) Transfers/other Closing volumes 390 (12) 378 IMPAIRMENT CHARGES AND EXPLORATION & EVALUATION EXPENSES $ Exploration & Evaluation ( E&E ) write off 1, Impairment of oil and gas assets 39,932 5,543 Total 40,989 6,313 E&E EXPENSES Minor write offs of expenditure relating to Exploration and Evaluation ( E&E ) assets were made during 2017 for non commercial prospects. IMPAIRMENT Pre tax impairment charges of $39.9 million ($24.0 million post tax) were recorded in the year (2016: $5.5 million) primarily caused by lower forecast production volumes from the Stella field as a result of the higher producing gas oil ratio observed following start up of operations. The impairment review was carried out on a fair value less cost of disposal basis, using risk adjusted cash flow projections discounted at a post tax discount rate of 9%. For details of the assumptions used, refer to the 2017 Financial Statements. ADMINISTRATION EXPENSES Tight management of underlying administration expenses maintain G&A costs at sub $1/boe $ General & Administration ( G&A ) 4,196 4,683 Share Based Payments ( SBP ) Non-recurring Delek transaction costs 5,468 - Total Administration Expenses 9,958 5,380 ADMINISTRATION EXPENSES Total underlying administrative expenses have reduced to $4.2 million in 2017 (2016: $4.7 million). Underlying G&A costs are tightly managed, with the business continuing to benefit from the savings secured as a result of resetting the cost base of the business following the fall in oil prices in Additional non recurring G&A costs of $5.5 million were incurred during the year specifically as a consequence of the Delek takeover transaction. 11

12 FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS GBP:US$ month end exchange rate $ Gain on Foreign Exchange 3,695 4,319 Total Gain on Foreign Exchange 3,695 4,319 Revaluation of Commodity Hedges (32,216) (119,248) Revaluation of Other Instruments (17) (32) Total Revaluation (Loss) (32,233) (119,280) Realised Gain on Commodity Hedges 7,720 87,908 Realised (Loss) on Other Instruments - (9,044) Total Realised Gain 7,720 78,864 Total Foreign Exchange & Financial Instruments (20,818) (36,097) FOREIGN EXCHANGE A foreign exchange gain of $3.7 million was recorded in 2017 (2016: $4.3 million gain) mainly due to volatility in the GBP:USD exchange rate, with fluctuations between 1.20 and 1.36 arising during the period and a closing rate of 1.35 on 31 December FINANCIAL INSTRUMENTS The Company recorded an overall $24.5 million loss on financial instruments for the year ended 31 December 2017 (2016: $40.4 million loss). A $7.7 million realised gain was made in 2017, equating to $1.5 of revenue per sales barrel of oil equivalent. This comprised a $2.5 million gain on oil hedges maturing during the year and a $5.2 million gain on gas hedges. Offsetting the realised gain was the revaluation of financial instruments still held as at 31 December The $32.2 million negative revaluation related to a negative revaluation of oil hedges of $25.9 million and a negative revaluation of gas hedges of $6.3 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 $25.9 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 2017 due to a strengthening of the oil forward curve. The $6.3 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 2017 the Company s commodity hedges were valued as a liability of $25.0 million based on valuations relative to the respective forward curves, comprising an oil hedging liability of $22.0 million coupled with a gas hedging liability of $3.0 million. This liability represents a strengthening in the commodities markets and therefore an improving outlook for oil and gas prices. FINANCE COSTS Underlying finance costs remain stable $ Bank interest and charges (10,846) (4,157) Senior notes interest (20,602) (15,319) Loan fee amortisation (5,134) (4,159) Accretion (8,757) (9,215) Other (4,762) (3,747) Total Finance Costs (50,103) (36,596) Finance costs charged to the income statement increased to $50.1 million in 2017 (2016: $36.6 million). This increase is primarily attributable to the cessation of capitalisation of interest relating to the Stella development now that the field is producing. All other finance costs have remained relatively stable year on year. 12

13 SHARE OF PROFIT IN ASSOCIATE FPF 1 investment generating returns $ Share of profit in associate 10,234-10,234 - The share of associate profit relates to the profit made by FPF 1 Limited, an associated company based in Jersey which owns the FPF 1 floating production facility. Profits are now being generated in this company as a result of the Stella field start up and the inflow of tariff income. This tariff income can be considered as a netting down of operating costs, with $18.9million of tariff income effectively returned to the business in This is offset by interest income relating to shareholders loans of $6.8 million and $1.9 million of other costs (mainly DD&A of the vessel) to give the $10.2 million net result in the income statement shown above. TAXATION No UK tax anticipated to be payable within the next 5 years $ UK Corporation Tax excluding Rate 79,258 87,818 Changes Impact of Change in Tax Rates - (57,961) Total Taxation 79,258 29,857 A tax credit of $79.3 million was recognised in the year ended 31 December 2017 (2016: $29.9 million credit). Significant components of the credit include a $40.1 million credit relating to the UK Ring Fence Expenditure Supplement; a $6.4 million credit relating to stock options exercised, and $2.2 million in respect of 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 will be made to Petrofac in 2022, being 5 years after completion of the SPA, of a sum calculated at the prevailing tax rate applied to the relevant capital allowances. A related deferred tax asset is recorded at 31 December 2017 of $96.5 million reflecting the expected future benefit of these additional capital allowances. 13

14 CAPITAL INVESTMENTS 2017 capital investment programme primarily focused on GSA development activities $ 000 Additions 2017 Development & Production ( D&P ) 173,580 Exploration & Evaluation ( E&E ) 3,077 Other Fixed Assets 43 Total 176,700 Excluding non cash Asset Retirement Obligation ( ARO ) revisions, capitalised interest costs and capitalisation of future Stella related payments to Petrofac, underlying capital expenditure on the asset portfolio in the period was approximately $76 million. The investment programme was centred on activities in the GSA, primarily being completion of the oil export pipeline works, execution of the Harrier field development programme and progression of Vorlich field development planning activities. 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 Financial Instrument Category Held-for-trading Ithaca Classification Cash, cash equivalents, restricted cash, derivatives, commodity hedges, long-term liability Subsequent Measurement Fair Value with changes recognised in net income Held-to-maturity - Amortised cost using effective interest Loans and Receivables Accounts receivable rate method. Other financial liabilities Accounts payable, operating bank loans, accrued liabilities Transaction costs (directly attributable to acquisition or issue of financial asset/liability) are adjusted to fair value initially recognised. These costs are also expensed using the effective interest rate method and recorded within interest expense. COMMODITIES The following table summarises the commodity hedges in place at 31 December Derivative Term Volume bbls Average Price $/bbl Oil Puts January 2018 March ,250, Oil Swaps January 2018 June ,864, Derivative Term Volume therms Average Price p/therm Gas Swaps January 2018 March ,888, In the fourth quarter of 2017 the Company entered into additional hedging contracts for 1.1 million barrels of 2018 and 2019 oil production using put options and swaps with a floor price of $60/bbl and 11 million therms of gas production using swaps with a floor price of 45p/therm. Incorporating this hedging with the Company s existing position, the Company has 7,800 boepd hedged at an average floor price of $50/boe for the 18 months to 30 June Full commodity price upside exposure has been retained on 40% of the oil volumes hedged. In summary, the total commodity hedging position for is comprised of: 3,400 bopd of oil swap contracts at an average price of $54/bbl 2,300 bopd of oil put options with a floor price of $61/bbl 70 million therms of gas swaps at an average price of 46p/therm 14

15 WORKING CAPITAL $ Dec Dec Increase / (Decrease) Cash & Cash Equivalents 30,542 27,199 3,343 Trade & Other Receivables 156, ,579 (2,544) Inventory 33,803 27,729 6,074 Other Current (Liabilities)/Assets (25,029) 7,183 (32,212) Trade & Other Payables (296,601) (236,928) (59,673) Net Working Capital* (101,250) (16,238) (85,012) *Working capital being total current assets less trade and other payables As at 31 December 2017 Ithaca had a net working capital credit balance of $101.3 million, including an unrestricted cash balance of $30.5 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 year to 31 December 2017 primarily as a result of the recategorisation of the Shell and BP prepayments from long term liabilities to current liabilities due to the maturity date of the agreements. CAPITAL RESOURCES Bank debt facilities refinanced in November 2017 DEBT FACILITIES In November 2017, the company refinanced its bank debt facilities to better align with the maturity of its senior unsecured notes and retain flexibility around future financing activities associated with delivering upon the growth objectives of the business. The Company extended the maturity of its senior reserves based lending ( RBL ) facility to May 2019 and retired its junior RBL facility. By temporarily constraining the RBL term to align with the maturity of the Company s existing $300 million senior unsecured notes (due July 2019) and retain full future refinancing flexibility, the debt availability under the new RBL facility has been reduced. The RBL has therefore been supplemented with a $140 million term loan, supported by Delek via a $70 million future acquisition fund and a corporate guarantee. In addition the Company has in place a $30 million unsecured parent company loan. Both these loans have maturities of June As at 31 December 2017, therefore, Ithaca has a $245 million senior RBL facility and a $140 million term loan. The availability of these facilities as at the same date was over $375 million. The facilities are based on conventional oil and gas industry financing terms and mature in May The combined annual interest payable on the facilities is LIBOR+2.6% based on current drawings. The facilities are for funding Ithaca's ongoing development operations, including a $45 million tranche to part fund Vorlich field development capital expenditures. The RBL is redetermined every six months, in April and October. Ithaca also has $300 million of senior unsecured notes that bear annual interest of 8.125%, payable biannually, maturing in July Ithaca has an option for early repayment of the notes, in full or in part. 15

16 The following table summarises the funds drawn under the facilities noted above. DEBT SUMMARY (M$) 31 Dec Dec RBL Facility Term Loan Senior Notes Delek Term Loan (1) Total Debt UK Cash and Cash Equivalents (30.6) (27.2) Net Drawn Debt Note this table shows debt repayable as opposed to the reported balance sheet debt which nets off capitalised RBL and senior note costs; (1) Delek term loan comprises a loan of $100M offset by security given of $70M The key covenants in the senior RBL are as follows: Total projected sources of funds must exceed the total projected uses of funds for the remaining term of the RBL 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 The Company was in compliance with all its relevant financial and operating covenants during the year. There are no historic or maintenance financial covenant tests associated with the term loan, senior unsecured notes or the parent company loans. Working capital driven cash outflow in the quarter 2017 CASHFLOW MOVEMENTS During the year ended 31 December 2017 there was a cash inflow from operating, investing and financing activities of approximately $3.3 million (2016 inflow of $15.7 million); as set out in the following graph. Cashflow from operations Cash generated from operating activities was $133.4 million. Revenues from the producing portfolio of assets were bolstered by the start up of production from the Stella field, combined with reduced unit operating costs. Cashflow from financing activities Cash used in financing activities was $32.0 million, being interest charges coupled with repayments of the RBL debt facility during the year, partly offset by the receipt of a term loan from Delek. Cashflow from investing activities Cash used in investing activities was $90.8 million, primarily associated with further capital expenditure on the GSA development (including capitalised interest). 16