MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

2015 HIGHLIGHTS Solid cashflow generation despite the material decline in Brent prices over the period

Decisive actions taken in 2015 to ensure the business is resilient to the lower oil price environment

Strong outlook – platform established to continue deleveraging the business while growing the value of the asset portfolio

GSA development at advanced stage of completion – production start-up anticipated in Q3 2016

•

Average production of 12,066 barrels of oil equivalent per day (“boepd”), above full year guidance (2014: 10,947 boepd)

•

$261 million cashflow from on-going operations , a 70% increase on 2014 ($153 million) driven by reduced operating costs and hedging gains

•

Cashflow per share $0.76 (2014: $0.55)

•

Loss after tax of $121 million (2014: $25 million) as result of a $203 million post-tax impairment charge arising from lower forecast future oil and gas prices

•

Major re-set of operating expenditure – unit operating cost of $31/boe in 2015, a 44% reduction on the previous year (2014: $55/boe) and 22% ahead of targeted savings

•

Major capital expenditure savings secured – 2015 investment programme delivered for $117 million, approximately 25% under budget

•

Sale of non-core Norwegian business – net cash receipt of $60 million and potential $30 million upside exposure

•

$66 million equity placing with Delek Group Ltd at a 39% premium to the 5 day volume weighted average share price prior to announcement – strengthening the balance sheet and providing additional financial flexibility

•

Substantial deleveraging - net debt reduced from a peak of over $800 million in the first half of 2015 to $665 million at year-end 2015

•

Completion of the “FPF-1” modifications programme remains on track for sail-away of the vessel in the previously guided May/June 2016 period, leading to anticipated first hydrocarbons from the Stella field in the third quarter of the year

•

Near term production forecast to more than double with start-up of the Stella field – long term growth underpinned by the Greater Stella Area satellite portfolio and leveraging the value of the infrastructure

•

Significant commodity price protection – average of 10,000 boepd hedged until mid-2017 at $61/boe, with a mark-to-market value of $127 million at year-end 2015

•

Increasing financial flexibility – continued deleveraging of the business within a balanced capital investment programme

•

Significant progress was made on execution of the GSA development in 2015, and first hydrocarbons remain scheduled in the third quarter.

•

The five well Stella development drilling campaign was successfully completed during the year, along with the subsea infrastructure installation activities required prior to arrival of the FPF-1 on location. The FPF-1 modifications programme, which is being undertaken by Petrofac in the Remontowa shipyard in Poland has made solid progress over the last twelve months and is in an advanced stage of completion.

•

Commissioning operations on the vessel are nearing completion and the marine work is progressing on schedule

•

Further strengthening of the GSA portfolio secured with the acquisition of a strategic nonoperated interest in the Vorlich discovery (transaction completion scheduled for early Q2 2016)

1

(1) Cashflow from on-going operations of $261 million less $21 million of net outflows from discontinuing fields (Beatrice, Athena and Anglia), provided for as onerous contracts in 2014, equates to overall cashflow from operations of $240 million

1

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

SUMMARY STATEMENT OF INCOME 2015 Average Production Average Realised Oil Price(1)

kboe/d

2014

12.1

10.9

54

97 363.6

$/bbl

Revenue(2)

M$

201.0

Hedging Cash Gain

M$

177.9

14.0

Revenue(2) (After Hedging)

M$

378.9

377.6

Opex

M$

(106.5)

(220.8)

G&A

M$

(9.8)

(12.0)

Foreign Exchange

M$

(1.7)

8.4

Cashflow from On-going Operations(3)

M$

261.0

153.2

DD&A & Impairment

M$

(520.5)

(608.8)

Non-Cash Hedging (Loss) / Gain

M$

(22.6)

161.2

Finance Costs

M$

(40.2)

(32.1)

Other Non-Cash Costs

M$

(4.1)

(6.0)

Taxation – Excluding Rate Changes

M$

245.7

307.9

M$

(40.3)

-

Earnings

– Reduced Tax Rates Impact

M$

(121.0)

(24.5)

Earnings excluding impact of impairment

M$

81.6

148.2

Cashflow Per Share(4)

$/Sh.

0.76

0.55

Earnings Per Share

$/Sh.

(0.35)

(0.07)

Adjusted Earnings Per Share(5)

$/Sh.

0.24

0.45

(1) Average realised price before hedging (2) Revenue including interest income and oil purchases less stock movements (3) 2015 Cashflow from On-going Operations of $261.0M less $21.0M onerous contract provision release = total cashflow from operations of $240.0M (4) Based on total cashflow from operations (5) Earnings per share adjusted to exclude impact of impairment charge

SUMMARY BALANCE SHEET M$ Cash & Equivalents Other Current Assets

31 Dec. 2015 12

31 Dec. 2014 19

372

446

1,113

1,525

Deferred Tax Asset

356

139

Other Non-Current Assets

211

229

Total Assets

2,063

2,359

Current Liabilities

(283)

(419)

Borrowings

(666)

(785)

Asset Retirement Obligations

(227)

(213)

Other Non-Current Liabilities

(93)

(97)

(1,270)

(1,514)

Net Assets

793

845

Share Capital

617

552

PP&E

Total Liabilities

Other Reserves

23

19

Surplus

153

274

Shareholders’ Equity

793

845

2

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

DEBT SUMMARY (M$) RBL Facility Corporate Facility Senior Notes Norwegian Tax Rebate Facility

31 Dec. 2015 376.8

31 Dec. 2014 480.6

-

-

300.0

300.0

-

17.4

Total Debt

676.8

798.0

UK Cash and Cash Equivalents

(11.5)

(17.3)

Net Drawn Debt

665.3

780.7

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

3

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

CORPORATE STRATEGY Ithaca Energy Inc. (“Ithaca” or the “Company”) is a North Sea oil and gas operator focused on the delivery of lower risk growth through the appraisal and development of UK undeveloped discoveries and the exploitation of its existing UK producing asset portfolio. Ithaca’s goal is to generate sustainable long term shareholder value by building a highly profitable 25kboepd North Sea oil and gas company. Execution of the Company’s strategy is focused on the following core activities: •

Maximising cashflow and production from the existing asset base

•

Delivering first hydrocarbons from the Ithaca operated Greater Stella Area development

•

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

•

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

•

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

CORPORATE ACTIVITIES Strong liquidity – available debt facilities of $815M at end 2015, while drawn net debt came in below forecast at $665M at end 2015

BANK DEBT FACILITIES During 2015 the Company extended and simplified its bank debt facilities, replacing its corporate facility with a junior Reserve Based Lending (“RBL”) facility and extending the tenor of its senior RBL to September 2018. These changes aligned the maturity of the two facilities and importantly removed the use of historic financial covenant tests that had been applicable on the corporate facility. The Company’s bank debt facilities are sized at $650 million: a $575 million senior RBL and a $75 million junior RBL. The facilities are based on conventional oil and gas industry borrowing base financing terms and are available to fund on-going development activities and general corporate purposes. In addition to these facilities, the Company has $300 million senior unsecured notes due July 2019, resulting in total Company debt facilities of $950 million. The Company completes a bi-annual redetermination process with its RBL bank syndicate, at the end of April and October, to review the borrowing capacity of its assets under the RBLs based on the technical and commodity price assumptions applied by the syndicate. Following the October 2015 redetermination the Company’s available bank debt capacity was set at $515 million (out of the total $650 million of RBL facilities), reflecting the lower future commodity price assumptions adopted by the banking syndicate during the review. When combined with the senior notes, this means the business has a total debt capacity of $815 million, which compares to net debt at the end of 2015 of $665 million. The Company continues to focus on maintaining a solid liquidity position with substantial deleveraging having already commenced even before first hydrocarbons from the GSA - total bank debt reduced during the year by 27% from over $500 million to $365 million at the year end. A robust financial position has been retained during this period of lower and more volatile oil prices as a result of various proactive measures taken during 2015 to increase financial strength and ensuring the Company has the sufficient flexibility to manage downside risks.

Equity investment completed at 51% premium to 30 day VWAP – providing additional flexibility to execute the financial and strategic priorities of the business

PREMIUM EQUITY PLACING In October 2015 a $66 million equity investment in the Company was completed with DKL Investments Limited, a wholly owned subsidiary of Delek Group Ltd. (“Delek”), in order to further strengthen the Company’s balance sheet, reduce bank debt and provide additional financial flexibility. Following completion of the placing, Delek holds a 19.9% interest in the issued and outstanding shares of the Company. Delek is an Israeli listed conglomerate with significant natural gas exploration and production activities in the Levant Basin in the Eastern Mediterranean. The investment was executed via a non-brokered private placement of 81,865,425 Common Shares in the capital of the Company at CAD$1.05 per share, equivalent to £0.53 per share. This represented a 19% premium to the CAD$0.88 per share closing price 4

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015 on the Toronto Stock Exchange (“TSX”) on the day prior to announcement of the placing, a 39% premium to the 5 day volume weighted average price (“VWAP”) and a 51% premium to the 30 day VWAP. DIRECTOR & EXECUTIVE CHANGES As a result of the Delek equity investment the Board of Directors increased from seven to nine directors with the appointment of two Non-Executive Director representatives nominated by Delek; Mr Joseph Asaf Bartfeld and Mr Yosef Abu. Mr Bartfeld is the President & Chief Executive Officer of Delek and has held a number of senior positions in the Delek Group including that of Chief Financial Officer over the last 20 years. Mr Bartfeld also serves as Chairman and Director on the Board of Directors of a number of Delek Group subsidiaries and affiliates. Mr Abu is the Chief Executive Officer of Delek Drilling Ltd, a subsidiary of Delek, prior to which he held senior consulting positions in the Israeli Ministries of Finance and Interior. In January 2016, Dr. Richard Smith was appointed to the executive team as Chief Commercial Officer. Dr. Smith has held the position of Corporate Development Manager at Ithaca for the last five years. He has over 19 years of experience in the oil and gas industry and wider energy sector, in various senior business development, corporate strategy and commercial positions.

Sale of the non-core Norwegian exploration business completed – Norwegian financing facility repaid and net initial cash payment of ~$30M received

SALE OF NORWEGIAN BUSINESS In July 2015 the Company completed the sale of its wholly owned subsidiary Ithaca Petroleum Norge AS (“Ithaca Norge”) to the Hungarian listed company MOL Plc for an initial consideration of $60 million plus the ability to earn additional bonus payments of up to $30 million dependent on exploration success from the existing licence portfolio. Following repayment and retirement of the Company’s Norwegian exploration financing facility and conventional working capital adjustments, a net cash payment of approximately $30 million was received. These funds were used to offset drawings under the Company’s existing RBL facilities. This transaction concluded the highly successful restructuring and monetisation of the Norwegian operations transferred as part of the Valiant Petroleum plc acquisition in April 2013. The Norwegian portfolio had no production or reserves associated with the licence interests.

5

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

PRODUCTION & OPERATIONS Solid 2015 production performance – in line with full year guidance 12.1 10.9

kboe/d

kboe/d

0.7

0.5

11.3

10.4

2014

2015 Oil

Gas

2015 PRODUCTION Average production in 2015 was 12,066 boepd, 94% oil (2014: 10,947 boepd), above full year guidance of 12,000 boepd. This represented a 10% increase on 2014, driven largely by inclusion of a full year contribution from the assets acquired in July 2014 from Sumitomo Corporation (the “Summit Assets”) and the results of various production enhancement activities undertaken during the year. These increases more than offset the reduction in volumes attributable to the planned cessation of production from the Beatrice and Jacky fields in January 2015, the scheduled maintenance shutdowns on the host facility serving the Cook field and the Sullom Voe Terminal that serves the Company’s Northern North Sea fields, along with natural field decline rates. OPERATIONS The producing asset portfolio performed well over the course of 2015, with solid operational uptime achieved across the main fields. The planned maintenance shutdown activities scheduled for the year were all completed efficiently, with the duration of the outage on the Cook field being shorter than forecast. Good progress was made in the year on all the main production enhancement activities. In the first quarter of 2015 water injection on the Causeway field was started up following completion of work on the Taqa-operated North Cormorant platform facilities and the electrical submersible pump on the Fionn field was brought into service. In late May first oil was achieved from the Ythan field, developed as a one well tie-back to the Don Southwest facilities. Following the completion of modification works to the Pierce field floating production, storage and offloading vessel (“FPSO”) to enable the tie-in of the third party Brynhild field in December 2014, Pierce production volumes were steadily increased over the course of 2015. In addition, a rolling well workover campaign was continued on the onshore Wytch Farm field during the year in order to sustain production rates. As part of the Company’s previously announced activities to high grade the portfolio and remove high cost marginal fields from the producing asset base, a number of measures were taken in 2015 to restructure the portfolio. The Company had elected in 2014 to retransfer the Beatrice facilities to Talisman, having successfully completed production operations on the adjacent Ithaca-operated Jacky field, and the planned retransfer process was completed in the first quarter of 2015. Production was also ceased from the Anglia field in the third quarter of 2015 and from the Athena field at the start of 2016, with the BW Athena FPSO being demobilised from the field in February 2016. These steps mean that the Company’s production portfolio is in line with the requirements demanded of the current oil price environment, with unit operating costs for the fields being approximately $30/boe. The carrying values of the Beatrice, Anglia and Athena fields were written down to nil at the end of 2014, with provisions made for any onerous contracts remaining until cessation of production from the fields. In March 2016, following the completion of Shell and ExxonMobil’s sale of the Anasuria FPSO vessel and associated feeder field interests, the Company took over operatorship of the Cook field, which uses the Anasuria as its host facility. 2016 PRODUCTION Base production in 2016, excluding any contribution associated with start-up of the Stella field during the year, is anticipated to be approximately 9,000 boepd (95% oil). This reflects the cessation of production from the Athena and Anglia fields, which accounted for approximately 1,000 boepd in 2015, along with no significant capital investment on the existing producing assets during the year and restricted production rates for the Pierce field in the first half of 2016 due to the need to complete remedial works on the subsea gas injection flowline. The additional production contribution during the year resulting from the start-up of Stella will depend on the exact timing of first hydrocarbons from the field. Prompt ramp up of production is anticipated following first hydrocarbons, leading to an initial annualised production rate for the GSA hub of approximately 16,000 boepd net to Ithaca.

Forecast Q1 2016 production in line with guidance

Production during the first quarter of 2016 is forecast to average approximately 9,000 boepd. This reflects acceleration of the planned 2016 Pierce field maintenance shutdown into the quarter in order to take advantage of the current period of restricted production rates noted above and reduced production from the Dons fields for execution of a well chemical treatment campaign.

6

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

GREATER STELLA AREA DEVELOPMENT GSA development activities are at an advanced stage of completion – Stella production start-up scheduled for Q3 2016

Main FPF-1 commissioning nearing completion with sail-away forecast for May / June 2016

Stella development drilling programme successfully completed in April 2015

All subsea infrastructure required prior to FPF-1 arrival now installed

Agreement entered into with Petrofac to provide enhanced incentivisation for the timely delivery of FPF-1 and additional contract cost clarity

Sales agreement executed with BP for Stella gas production

Ithaca’s focus on the GSA is driven by the monetisation of over 30MMboe of net 2P reserves within the existing portfolio and the generation of additional value via the wider opportunities provided by the range of undeveloped discoveries surrounding the Ithaca operated production hub. The development involves the creation of a production hub based on deployment of the FPF-1 floating production facility located over the Stella field, with onward export of oil and gas. To maximise initial oil and condensate production and fill the gas processing facilities on the FPF-1, the hub will start-up with five Stella wells. Further wells will then be drilled in the GSA post first hydrocarbons to maintain the gas processing facilities on plateau. FPF-1 MODIFICATION WORKS The FPF-1 modifications programme, which is being undertaken by Petrofac in the Remontowa shipyard in Poland, has made solid progress over the last twelve months and is in an advanced stage of completion. Commissioning operations on the vessel are nearing completion and the marine work is progressing on schedule. As announced at the start of 2016, sail-away of the FPF-1 is forecast for the May / June 2016 period, leading to anticipated first hydrocarbons from the Stella field in the third quarter. Close out of the modifications programme is the critical path item for start-up of production from the field. DRILLING PROGRAMME The five well Stella development drilling programme was successfully completed in April 2015 and the ENSCO 100 rig demobilised from the field. The wells have all been successfully cleaned up and suspended in a manner that allows production to commence without the requirement for any further intervention activity once the FPF-1 floating production facility is on location and hooked up. In total the wells have achieved a combined maximum flow test rate during clean-up operations of over 53,000 boepd (100%). This well capacity significantly de-risks the initial annualised production forecast for the GSA hub of approximately 30,000 boepd (100%), 16,000 boepd net to Ithaca. SUBSEA INFRASTRUCTURE WORKS The 2015 subsea infrastructure installation campaign was successfully concluded as planned in the fourth quarter of 2015, with all the subsea infrastructure that is required to be installed prior to the arrival of the FPF-1 on location in place. The only remaining subsea workscope prior to first hydrocarbons relates to the installation and hook-up of the dynamic risers and umbilicals connecting the infrastructure on the seabed to the FPF-1. This activity will be complete once the vessel has been anchored on location. FPF-1 MODIFICATIONS CONTRACT INCENTIVISTION In September 2015 the Company entered into an agreement with Petrofac in respect of the FPF-1. The agreement provides enhanced incentivisation for the timely delivery of the vessel and also provides important contract cost clarity, thereby ensuring efficient execution of the remaining FPF-1 modification works. The key terms of the agreement are: •

All costs of modifying the FPF-1 above the contract cost cap will continue to be fully paid by Petrofac as incurred;

•

Ithaca will pay Petrofac $13.7 million in respect of final payment on variations to the contract, with payment deferred until three and a half years after first production from the Stella field;

•

A further payment to Petrofac will be made by Ithaca dependent on the timing of sail-away of the FPF-1. The maximum incentive payment of $34 million was achievable for delivering sail-away of the vessel from the shipyard prior to the end of March 2016, eroding on a daily basis to zero by 31 July 2016. The incentive payment ultimately earned by Petrofac will also be deferred until three and a half years after first production from the Stella field.

GAS SALES AGREEMENT In September 2015 the Company entered into a life of field gas sales agreement with BP Gas Marketing Limited (“BP”) for the sale of gas produced from the Stella and Harrier fields. The contract reference price is the UK “NBP” spot price. The agreement includes the ability for Ithaca, at its option, to receive up to £10 million of prepayments for future gas sales to BP, similar to the arrangements available with Shell Trading International Limited for oil sales.

7

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

COMMODITY HEDGING Significant downside commodity price protection from hedging in place

As part of its overall risk management strategy, Ithaca’s commodity hedging policy is centred on underpinning revenues from existing producing assets at the time of major capital expenditure programmes and locking in paybacks associated with asset acquisitions. Any hedging is executed at the discretion of the Company as there are no minimum requirements stipulated in any of the Company’s debt finance facilities. As of 1 January 2016 the Company had 10,000 boepd hedged at $61/boe for the 18 months to June 2017. This total is comprised of: • 11,500 boepd (52% oil) at $60/boe in 2016 • 7,000 boepd (50% oil) at $62/boe in the first six months of 2017. The above figures include 151 million therms of gas hedging (approximately 15 billion cubic feet), with a price floor of £0.57/therm (~$10/MMbtu). The gas hedging is in the form of put options, the financial benefit of which is realised regardless of production in the relevant period. As at 1 January 2016 the Company’s commodity hedges were valued at $127 million, $69 million for oil hedges and $58 million for gas hedges, based on valuations relative to the respective oil and gas forward curves.

LICENCE PORTFOLIO ACTIVITIES Strategic asset acquisition close to GSA hub – opportunity to leverage infrastructure value

VORLICH ACQUISITION In line with Ithaca’s strategic objective to increase value from the GSA infrastructure through the acquisition of interests in potential satellite fields for the FPF-1, the Company signed a sale and purchase agreement with TOTAL E&P UK Limited in January 2016 to obtain a 20% non-operated interest in Licence P363 (block 30/1c), effective 1 July 2015. The licence is operated by BP plc and contains approximately 80-90% of the Vorlich discovery, implying an approximately 17% interest in the overall discovery to Ithaca. Vorlich is located 10 kilometres north of the GSA hub. Vorlich was discovered and appraised in 2014 with exploration well 30/1f-13A,Z and 13Z. The well encountered hydrocarbons in a Palaeocene sandstone reservoir in block 30/1c and a subsequent sidetrack into block 30/1f confirmed the westerly extension of the discovery. In line with the requirements of the Vorlich licence, the work programme for 2016 is centred on the preparation and submission for approval of a Field Development Plan (“FDP”) by the end of the year. A minimal consideration is payable at completion of the transaction, with additional contingent payments at FDP approval and upon reaching a reserves recovery threshold. The acquisition is subject to normal regulatory approvals and is expected to complete early in the second quarter of 2016. At completion the consideration paid will be subject to normal industry adjustments to reflect costs incurred since the effective date.

High grading of asset portfolio – disposal of noncore licence interests

NON-CORE LICENCE RELINQUISHMENTS As announced in November 2015, as part of routine portfolio review activities the Company elected to divest its 10% working interest in the Scolty/Crathes discoveries to EnQuest plc for a nominal sum and to transfer its 20% working interest in licence P1792 that contains the Beverley prospect and Evelyn discovery to Shell UK Limited. The Company has also relinquished its 55% interest in the South West Heather discovery. Divestment of these non-core licence interests is driven by the financial and strategic metrics of the potential development opportunities being insufficient to meet Ithaca’s investment criteria in the prevailing Brent price environment. In the end-2014 independent reserves evaluation performed by Sproule International Limited, an independent qualified reserves evaluator, (“Sproule”) these licences accounted for approximately ten million barrels of net proved and probable reserves (“2P”).

8

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

RESERVES •

Total proved and probable (“2P”) reserves at 31 December 2015, as independently assessed by Sproule International Limited, plus estimated reserves associated with the Vorlich licence are 57MMboe. The acquisition of the Vorlich licence is scheduled to complete early in the second quarter of 2016.

•

After accounting for non-core licence relinquishments during the year (approximately 10MMboe), changes to the Company’s 2P reserves have been modest despite a significant reduction in assumed future oil and gas prices.

•

The Company has a balanced producing and development asset reserve base, with approximately 22MMboe or 40% of total 2P reserves associated with producing assets. This is forecast to increase to approximately 65% with the start-up of production from the Stella field.

•

The 2P reserves post-tax net present value discounted at 10% (“NPV-10”) assessed by Sproule as at 31 December 2015 was $1,010 million. This reflects an average drop of over 30% in medium term oil and gas price assumptions and approximately 15% thereafter when compared to the prior year’s evaluation.

•

The movement in total 2P reserves between end-2014 and end-2015 is summarised in the following table: 2P Reserves

MMboe

Opening Reserves – 31 December 2014

70.5

Production*

(4.1)

Relinquishments

(10.4)

Revisions - Economic / Technical

(2.8)

Closing Reserves – 31 December 2015

53.2

Vorlich**

3.8

Closing Reserves

57.0

* Excludes 0.3MMboe Athena production - no field reserves attributed to either the opening or closing balance ** Vorlich licence acquisition forecast to complete in Q2 2016

9

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

OPERATING EXPENDITURE Unit operating costs $31/boe in 2015, 44% lower than 2014 and 22% below budget

As part of managing and minimising the impact of the abrupt decline in oil prices since the second half of 2014, the Company has taken a number of important steps to protect the business from a prolonged period of weak oil prices. In addition to the cashflow protection provided by the oil and gas price hedging that has been put in place, the Company and its partners continue to actively work on securing supply chain cost efficiencies and reductions, removing overheads and resetting the cost base to reflect the requirements of the current environment.

2015 Opex / boe evolution

37 33 28

Q1

Q2

Q3

25

Q4

When combined with the cessation of operations at the Company’s legacy high cost fields and importantly the retransfer of the Beatrice facilities to Talisman in Q1 2015, the 2015 financial results show a step change in unit operating costs compared to the previous year. Specifically, unit operating costs have reduced by 44% to $31/boe compared to 2014 (2014: $55/boe), markedly down from what was the anticipated level at the start of the year of approximately $40/boe. This unit operating expenditure reflects inclusion of the costs associated with the Athena and Anglia fields, which were provided for in Q4 2014 as an onerous contract provision. The provision was made and the book value of the fields fully written down in 2014 due to the expectation that 2015 would be the last year of production for the fields given costs were likely to exceed revenues in the current price environment. In 2016 forecast unit operating expenditure associated with base production volumes is expected to be approximately $30/boe, reducing to under $25/boe upon Stella start-up.

CAPITAL EXPENDITURE $117 million 2015 capital expenditure programme, ~70% lower than 2014

Total capital expenditure in 2015 was $117 million (2014: $370 million). This was over $30 million lower than initially budgeted primarily driven by reduced GSA subsea infrastructure installation costs as well as the removal of expenditure following sale of the Norwegian business. Expenditure on the planned capital expenditure programme for 2016 is anticipated to total approximately $50 million, the majority of which relates to the GSA, including activities required to prepare the Vorlich FDP for approval. There are a number of production enhancement opportunities within the existing producing asset portfolio that could be added to the planned capital expenditure programme, should the prevailing economics justify inclusion. The sanction of all such expenditures is within the control of the Company.

NET DEBT Deleveraging commenced in H2 2015 with over $120 million reduction in debt from Q2 2015

As anticipated the Company commenced deleveraging the business in 2015. Net debt was reduced from a peak of over $800 million in the first half of 2015 to $665 million at 31 December 2015. This reduction reflects the benefit of strong operating cashflow generation, lower capital expenditures, the cash received from sale of the non-core Norwegian business, as well as proceeds of the premium equity placing completed in October 2015. It is anticipated that deleveraging of the business will continue through 2016, with a step change in this profile arising upon the start-up of Stella production. Net debt at the end of Q1 2016 is expected to be approximately $635 million.

10

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

SELECTED ANNUAL INFORMATION •

Revenues have reduced by approximately 45% in 2015 primarily as a result of a decrease in the realised oil price, which was also the main driver behind the reduction in revenues in 2014 compared to 2013.

•

In 2015 a non-cash impairment charge of $203 million (post-tax) turned a pre impairment post-tax profit of $82 million into a post-tax loss of $121 million. A similar impairment charge ($173 million post-tax) was recorded in 2014. These impairments resulted from materially lower near term oil prices assumptions.

•

Total assets decreased from 2014 to 2015 mainly as a result of the impairment write downs driven by the oil price environment. The movement from 2013 to 2014 was primarily due to the acquisition of the Summit Assets and significant capital investment on the GSA development and production enhancement activities, partially offset by the impairment write downs as noted above. Years Ending 31 December ($’000)

2015

2014

2013

Total Revenue

206,975

378,593

413,937

Underlying cashflow from operations(1)

261,048

181,465

241,144

81,612

139,993

173,199

(Loss)/Profit After Tax (post impairment)

(121,005)

(24,535)

144,686

Total Assets

2,062,881

2,358,775

1,978,687

(985,785)

(1,094,571)

(639,786)

(Loss)/Profit After Tax (pre impairment)

Total Non-Current Liabilities (2)

(0.35)

(0.07)

0.48

(0.35)

(0.07)

0.47

Cashflow Per Share ($/Sh.) (2)

0.76

0.55

0.80

Cashflow Per Share – Fully Diluted ($/Sh.) (2)

0.76

0.55

0.78

Weighted Average No. Shares (000s)

345,667

328,381

301,525

Weighted Average No. Shares – diluted (000s)

345,667

329,952

307,888

Net Earnings Per Share ($/Sh.)

Net Earnings Per Share – Fully Diluted ($/Sh.)

(1) (2)

(2)

Refer explanatory footnote per page 1 Weighted average number of shares

11

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

2015 RESULTS OF OPERATIONS COMMODITY PRICES

Average Brent Price

$/bbl

2015

2014

%

52

99

-47%

The 2015 financial results reflect the impact of the significant fall in Brent prices since the middle of 2014. On a year-on-year basis, the average annual Brent price has decreased by $47/bbl or 47% between 2014 and 2015. While this has had a significant negative impact on revenues, the fall in Brent has been materially mitigated during the year by the significant oil price hedging protection the Company had put in place.

REVENUE Revenue decreased by $171.6 million in 2015 to $207.0 million (2014: $378.6 million) primarily as a consequence of the $43/bbl or 44% decrease in the realised oil price prior to taking into account hedging.

Revenue $379M 89

90

$207M 35 42

100

59 100

2014

Q1

70

Q2

Q3

2015 Q4

While produced volumes increased by 10% in 2015 compared to 2014 (refer to the Production & Operations section above), sales volumes recorded in revenues during the year decreased by approximately 2%. The decrease was as a result of Athena and Anglia liftings being recorded against the onerous contracts provision from Q4 2014 and an overall underlift across the Cook, Pierce and Wytch Farm fields. Adjusting for Athena and Anglia sales volumes would result in an increase in 2015 sales volumes of 7%. The reduction in realised price was offset to a significant extent by a realised hedging gain of $41 per sales barrel in the year ($34 per sales barrel excluding the benefit of the accelerated hedging reset of $33 million), resulting in a $177.9 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. Average Realised Price

2015

2014

Oil Pre-Hedging

$/bbl

54

97

Oil Post-Hedging

$/bbl

95

100

12

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

COST OF SALES $’000

2015

2014

Operating Expenditure

106,468

220,806

DD&A

120,230

167,378

6,030

14,640

-

1,087

232,728

403,911

Movement in Oil & Gas Inventory Oil purchases Total

Operating Expenditure $221M

Cost of sales decreased in 2015 by over 40% to $232.7 million (2014: $403.9 million) driven by decreases in operating costs, depletion, depreciation and amortisation (“DD&A”) and movement in oil and gas inventory.

59

69

$106M 23 26

52

30 41

28

2014 Q1

2015 Q2

Q3

Q4

DD&A $167M 46 $120M 27

38

31 51 32 33

31

2014

2015

Q1

OPERATING EXPENDITURE Reported operating costs decreased by 52% in the year to $106.5 million (2014: $220.8 million). The main reasons for this reduction are: i) significant savings realised across the portfolio as a result of supply chain contract cost renegotiations and contractor rate reductions; ii) replacement of production from the high cost Beatrice and Jacky fields with lower cost volumes from the Summit Assets; iii) the absence of the 2013 Sullom Voe Terminal catch-up cost that was charged in 2014; and, iv) exclusion of $29.9 million of 2015 Athena and Anglia costs provided for under an onerous contract provision in Q4 2014.

Q2

Q3

Q4

The unit operating costs for 2015 (inclusive of Athena and Anglia) were $31/boe. This represents a reduction of 44% compared to the equivalent rate of $55/boe for 2014. Absent these two fields, the unit operating cost for 2015 was $26/boe. DD&A The unit DD&A rate for the year decreased significantly to $27/boe (2014: $42/boe), resulting in a total DD&A expense for the year of $120.2 million (2014: $167.4 million). This reduction was mainly attributable to a different contributing field mix, with production coming increasingly from the fields with low DD&A rates such as Cook, Wytch Farm and Pierce, as opposed to high DD&A rate fields in 2014 such as Beatrice, Jacky, Athena and Anglia. The blended DD&A rate in 2015 has been further reduced by the write downs booked in 2014 as a consequence of the change in the oil price environment. The 2015 DD&A rate and charge noted above is before the $386.7 million impairment booked at year end 2015. DD&A rates are therefore expected to decrease further in 2016. MOVEMENT IN INVENTORY An oil and gas inventory movement of $6.0 million was charged to cost of sales in 2015 (2014 charge of $14.6 million). There was an underlift during the year resulting in oil inventory build-up for the Cook, Pierce and Wytch Farm fields, which was subsequently lifted and sold post year-end. However, a charge arises as a result of the underlift being more than offset by a reduction in value of oil inventory over the year across all fields as a result of the fall in oil prices. This effect was exaggerated by the increased valuation at 2014 year end of volumes from the Cook field as a result of sales having been made earlier in 2014 at higher oil prices but which remained unlifted at 2014 year end.

Movement in Operating Oil & Gas Inventory Opening inventory Production Liftings/sales Transfers/other Closing volumes

Oil

Gas

kbbls

kboe

366

Total kboe 3

369

4,116

292

4,408

(4,001)

(302)

(4,303)

(9) 472

4 (3)

(5) 469

13

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

IMPAIRMENT CHARGES AND EXPLORATION & EVALUATION EXPENSES $’000 Exploration & Evaluation (“E&E”) write off Impairment of oil and gas assets Impairment of goodwill Total

2015

2014

30,522

7,105

386,679

441,457

13,604

-

430,805

448,562

Exploration and evaluation write-off expenses of $30.5 million were recorded in the year (2014: $7.1 million). This primarily relates to the drilling of the unsuccessful Snømus exploration well in Norway in Q2 2015, the costs for which were paid for by MOL Plc as part of the completion price adjustments for the divestment of the Norwegian business. Pre-tax impairment charges of $400.3 million ($202.6 million post-tax) were recorded in the year (2014: $441.5 million) driven by the lower commodity price environment leading to a decrease in asset valuations. The impairment review was carried out on a fair value less cost of disposal basis, using riskadjusted cash flow projections discounted at a post-tax discount rate of 9%. For details of the assumptions used, refer to the 2015 Annual Financial Statements.

ADMINISTRATION EXPENSES $’000 General & Administration (“G&A”) Share Based Payments (“SBP”) Total Administration Expenses

Administration expenses reduced through on-going cost reduction measures

2015

2014

9,763

11,954

172

1,983

9,935

13,937

Total administrative expenses were reduced by 29% to $9.9 million in 2015 (2014: $13.9 million) due to a number of initiatives including reductions in contractor rates and a decrease in both employee and contractor numbers. In addition the 2015 cost includes approximately $2 million (pre-tax) of overhead costs associated with the Norwegian operations that were sold in July 2015 with recovery of the costs achieved as part of the overall deal completion. Share based payment expenses decreased as a result of fewer options being granted in 2015 and therefore lower amortisation expense throughout 2015. In addition, in line with the Company’s accounting policy, previously recognised compensation expense associated with the unvested portion of forfeited/expired stock options was reversed in Q4 2015 leading to an overall reduction in the annual SBP expense.

14

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

FOREIGN EXCHANGE & FINANCIAL INSTRUMENTS $’000 (Loss)/gain on Foreign Exchange

2015 (1,670)

2014 8,405

Realised gain on Financial Instruments

177,928

14,045

Revaluation of Financial Instruments

(22,602)

161,201

Total Foreign Exchange & Financial Instruments

153,656

183,651

A foreign exchange loss of $1.7 million was recorded in 2015 (2014: $8.4 million gain). While the majority of the Company’s revenue is US dollar denominated, expenditures are predominantly incurred in British pounds, although some US dollar and Euro denominated costs are also incurred. Consequently, general volatility in the GBP:USD exchange rate, with the rate moving from 1.55 at 1 January 2015 to 1.48 at 31 December 2015 and fluctuations throughout the year of between 1.46 and 1.59, is the primary factor underlying foreign exchange gains and losses. In addition, significant Stella developmentrelated payments were made in the year, particularly in the second quarter during a period of increased volatility, resulting in a modest overall loss despite the overall fall in the GBP:USD exchange rate during the year.

GBP:US$ month end exchange rate 1.58 1.56 1.54 1.52 1.50 1.48

Jan

Dec

The Company recorded an overall $155.3 million gain on financial instruments for the year ended 31 December 2015 (2014: $175.2 million gain). A $177.9 million realised gain was made in 2015. This comprised a $162.7 million gain on oil hedges maturing during the year (at an average exercise price of $85/bbl compared to an average Brent price of $52/bbl), combined with a $14.1 million gain on gas hedges and $1.1 million gain on foreign exchange and interest instruments. The total realised gain of $177.9 million was partially offset by a $22.6 million negative revaluation of instruments as at 31 December 2015. This revaluation resulted from a negative revaluation of oil hedges of $56.7 million, partly offset by a positive revaluation of gas and other hedges of $33.4 million and $0.7 million, respectively. 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 $56.7 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 gains, partially offset by an increase in the value of the remaining oil hedges at the end of 2015 based on the decrease in the Brent oil forward curve ($70/bbl average to the end of Q2 2017 as at Dec 2014 vs $42/bbl average as at Dec 2015). The positive revaluation of gas hedges mainly related to an increase in the value of remaining gas hedges at the end of 2015 based on the decrease in the gas forward curve, offset partly by the realisation of hedged gas volumes during the year. As of 1 January 2016 the Company’s commodity hedges were valued at $127 million, $69 million for oil hedges and $58 million for gas hedges based on valuations relative to the respective oil and gas forward curves.

15

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

FINANCE COSTS $’000

2015

2014

(7,384)

(12,993)

Senior notes interest

(15,009)

(7,831)

Finance lease interest

(1,048)

(415)

(71)

(160)

Bank interest and charges

Non-operated asset finance fees Prepayment interest

(2,059)

(716)

Loan fee amortisation

(5,591)

(4,232)

Accretion Total Finance Costs

(9,092)

(5,724)

(40,254)

(32,071)

Finance costs increased to $40.3 million in 2015 (2014: $32.1 million). This rise is attributable to a full year of interest costs on the senior unsecured notes in 2015, compared to only six months in 2014, partly offset by a decrease in RBL bank interest resulting from a significant deleveraging of the business in the second half of the year. Net drawn bank debt reduced from $481 million at 31 December 2014 to $365 million at 31 December 2015. Accretion costs increased by $3.4 million compared to 2014 following inclusion of a full year of decommissioning liabilities associated with the Summit Assets.

TAXATION $’000

2014

248,226

Impact of change in tax rates

(40,291)

-

(2,523)

(4,741)

Petroleum revenue tax Total Taxation

No UK tax anticipated to be payable prior to 2020

2015

UK & Norway corporation tax (“CT”) – excluding CT rate changes

205,412

312,682

307,941

A tax credit of $205.4 million was recognised in the twelve months ended 31 December 2015 (2014: $307.9 million credit). Included in the credit relating to UK and Norway taxation of $248.2 million is a $73.9 million credit relating to the UK Ring Fence Expenditure Supplement and $55.5 million in respect of additional capital allowances recognised in relation to Stella for expenditure incurred by Ithaca but paid by Petrofac (refer to note 25 in the 2015 Consolidated Financial Statements). This UK and Norway credit is offset by a deferred tax charge of $40.3 million relating to reductions in the Supplementary Charge and Petroleum Revenue Tax (“PRT”) rates enacted in the period. The UK government announced in its March 2015 budget that the effective rate of corporate income tax on oil and gas companies would be reduced from 62% to 50% with effect from 1 January 2015. The reduction was enacted on 30 March 2015. This resulted in a charge of $50.9 million relating to deferred Corporation Tax, partially offset by a credit of $10.6 million relating to the impact of a reduction in the Petroleum Revenue Tax (“PRT”) rate from 50% to 35% on the deferred PRT liability in the balance sheet. As a result of the above factors, the loss before tax of $326.4 million is reduced to a loss after tax of $121.0 million (2014: $24.5 million loss) and absent the impact of the change in tax rates would reduce further to $80.7 million. It was announced in the UK Budget on 16 March 2016 that the Supplementary Charge in respect of ring fence trades ("SCT") will be reduced from 20% to 10% with effect from 1st January 2016. This will reduce the Company's future SCT charge accordingly. The impact of the 10% reduction in the Supplementary Charge will reduce the net deferred tax assets by approximately $87 million. Further the rate of Petroleum Revenue Tax ("PRT") is to be reduced for chargeable periods beginning on or after 1 January 2016 from 35% to 0%. This will eliminate the Company's future PRT tax charge from 1 January 2016. If the deferred PRT liability as at 31/12/2015 was re-measured at the new PRT rate this would lead to a reduction in the net deferred PRT liability of $22 million. An immediate cash benefit of $3-$5 million per annum will be realised from the effective removal of PRT on the Wytch Farm field while the SCT cash benefits will be realised following utilisation of the UK tax 16

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015 allowances pool. The non-cash charge of $65 million associated with both tax rate changes will impact the financial statements in 2016 once the rate change has been enacted.

CAPITAL INVESTMENTS $’000

Additions 2015

Development & Production (“D&P”)

141,318

Exploration & Evaluation (“E&E”)

30,263

Other Fixed Assets

717

Total

2015 capital investment programme primarily focused on GSA development activities

172,298

Capital additions to development and production (“D&P”) assets totalled $141.3 million in 2015. These additions related primarily to activities associated with the GSA development, being completion of the Stella drilling campaign in April 2015 and subsea infrastructure installation operations (as described above), as well as completion of the Ythan field development in the first half of the year. Capital additions to E&E assets in 2015 were $30.3 million relating largely to drilling of the Snømus prospect in Norway, the costs of which were reimbursed upon completion of the sale of the Norwegian operations to MOL Plc. Total capital expenditure in 2015 excluding Norway, capitalised interest costs and non-cash additions relating to decommissioning was approximately $117 million.

WORKING CAPITAL $’000 Cash & Cash Equivalents Trade & Other Receivables Inventory Other Current Assets Trade & Other Payables Net Working Capital*

31 Dec. 2015

31 Dec. 2014

Increase / (Decrease)

11,543

19,381

(7,838)

223,749

267,887

(44,138)

20,900

27,481

(6,581)

126,887

150,760

(23,873)

(275,907)

(392,131)

116,224

107,172

73,378

33,794

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

As at 31 December 2015 Ithaca had a net working capital balance of $107.2 million, including an unrestricted cash balance of $11.5 million invested in money market deposit accounts 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. First Oil Expro Limited (“First Oil”) went into administration post year end with a net amount owing to Ithaca at the year end of $0.5 million. This relates to costs incurred after cessation of production from the Anglia field. These costs are expected to be recovered from funds put in place by First Oil to a Trustee in respect of decommissioning of the field. Working capital movements are driven by the timing of receipts and payments of balances and fluctuate in any given quarter. A significant proportion of Ithaca’s accounts receivable balance is with customers and co-venturers in the oil and gas industry and is subject to normal joint venture/industry credit risks. Net working capital has increased over the twelve month period to 31 December 2015 mainly as a result of increased settlement of payables associated with the on-going GSA development programme. Trade and other payables were particularly high at year-end 2014 compared to the end of 2015 due to drilling activity on both the Stella and Ythan fields. This was partially offset by a reduction in trade and other receivables, with the clearing of the Norwegian tax asset upon divestment of the Norwegian operations during the year combined with a reduction in the financial instrument asset values as a result of realisations during 2015.

17

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

CAPITAL RESOURCES

Bank debt facilities simplified and extended in 2015. Net debt reduced to $665 million at end 2015

DEBT FACILITIES At 31 December 2015 Ithaca had two UK bank debt facilities, being the $575 million senior RBL Facility and the $75 million junior RBL Facility, both due September 2018. Following the October 2015 redetermination the Company’s available bank debt capacity was set at $515 million (out of the total $650 million of RBL facilities), reflecting the lower future commodity price assumptions adopted by the banking syndicate during its review (further information is provided in the “Corporate Activities” section above). The Company also had $300 million senior unsecured notes, due July 2019. At 31 December 2015 the Company had unused and available UK bank debt facilities, including cash on deposit, totalling approximately $150 million, with approximately $377 million drawn under the RBL facility. The Company’s bank debt facilities are expected to be sufficient to ensure that adequate financial resources are available to cover anticipated future commitments when combined with existing cash balances and forecast cashflow from operations. As noted above, the bank debt facilities are subject to semi-annual redeterminations of available debt capacity using forward looking assumptions, of which future oil and gas prices are a key component. Movements in forecast commodity prices can therefore have a significant impact on available debt capacity and limit the Company’s ability to borrow. The Company was in compliance with all its relevant financial and operating covenants during the year. The key covenants in the senior and junior RBL facilities are: •

A corporate cashflow projection showing total sources of funds must exceed total forecast uses of funds for the later of the following 12 months or until forecast first oil from the Stella field.

•

The ratio of the net present value of cashflows secured under the RBL for the economic life of the fields to the amount drawn under the facility must not fall below 1.15:1.

•

The ratio of the net present value of cashflows secured under the RBL for the life of the debt facility to the amount drawn under the facility must not fall below 1.05:1.

There are no financial maintenance covenant tests associated with the senior notes.

Norwegian tax refund facility repaid and retired

2015 cashflow evolution

NORWEGIAN TAX REFUND FACILITY Following completion of the transaction with MOL Plc for the sale of the Company’s Norwegian business on 8 July 2015, the Company’s NOK 600 million Norwegian tax refund facility was fully repaid and retired. 2015 CASHFLOW MOVEMENTS During the twelve months ended 31 December 2015 there was a cash outflow from operating, investing and financing activities of approximately $7.8 million (2014 outflow of $44.1 million); as set out in the following graph. M$ 250

54 200

150

240

135

100

50

0

59 19 Cash @ 01.01.2015

Operating Activities

Financing Activities

Investing Activities

Working capital

12 Cash @ 31.12.2015

18

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

Cashflow from operations Cash generated from operating activities was $240.0 million. Revenues from the producing portfolio of assets were bolstered by the substantial hedging programme in place while operating costs reduced by over 50% in the year. Cashflow from financing activities Cash used in financing activities was $54.1 million, largely due to repayments of the debt facilities during the year ($81.3 million) combined with interest and bank charges on the RBL and Senior Notes ($38.5 million), partially offset by the $66.1 million equity investment in the Company completed in October 2015. Cashflow from investing activities Cash used in investing activities was $134.8 million, primarily associated with further capital expenditure on the GSA development (including capitalised interest), together with Ythan well costs.

COMMITMENTS $’000

1 Year

2-5 Years

5+ Years

Office Leases

240

300

-

Licence Fees

602

-

-

Engineering

8,932

-

-

Total

9,774

300

-

The Company’s commitments relate primarily to completion of the capital investment programme on the GSA development. Given the highly advanced status of the development, these commitments are relatively modest and are forecast to be funded from the operating cashflows of the business.

19

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

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: Financial Instrument Category Held-for-trading

Ithaca Classification

Subsequent Measurement

Cash, cash equivalents, restricted cash, derivatives, commodity hedges, long-term liability

Fair Value with changes recognised in net income

Held-to-maturity

-

Loans and Receivables

Accounts receivable

Amortised cost using effective interest 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.

The classification of all financial instruments is the same at inception and at 31 December 2015. The table below presents the total gain / (loss) on financial instruments that has been disclosed through the statement of comprehensive income. $’000

2015

Revaluation Forex Forward Contracts Revaluation of Interest Rate Swaps Revaluation of Other Long Term Liability

609

2014 (4,474)

(180)

(167)

307

2,680

Revaluation of Commodity Hedges

(23,338)

163,162

Total Revaluation (Loss) / Gain

(22,602)

161,201

Realised Gain on Forex Contracts Realised Gain on Commodity Hedges Realised (Loss) on Interest Rate swaps

1,512

4,028

176,773

10,342

(357)

(325)

Total Realised Gain

177,928

14,045

Total Gain on Financial Instruments

155,326

175,246

COMMODITIES The following table summarises the commodity hedges in place at the end of the year. Derivative

Term

Volume bbl

Oil Swaps

Jan 2016 – June 2017

2,520,837

Oil Capped Swaps

Jan 2016 – June 2016

Derivative

Term

Gas Puts

Jan 2016 – June 2017

Gas Swaps

Jan 2016 – March 2017

303,146 Volume Therms

Average Price $/bbl 65* 64* Average Price p/therm

150,500,000

63*

8,225,931

47*

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

20

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015 FOREIGN EXCHANGE The Company enters into forward contracts as a means of hedging its exposure to foreign exchange rate risks. As at the end of the year, the Company had £3.2 million per month hedged at a forward rate of $1.48 : £1 for the period January to December 2016. INTEREST RATES The Company enters into interest rate swaps as a means of hedging its exposure to interest rate risks on the loan facilities. As at the end of the year, the Company had hedged interest payments on $50 million of drawn debt at 1.24% for the period January to December 2016.

Q4 2015 FINANCIAL RESULTS Average realised oil prices in Q4 2015 were $45/bbl or 42% lower than the corresponding period in 2014 as a consequence the fall in Brent prices. While this significant decrease had a major impact on sales revenue, the fall from $88.9 million in Q4 2014 to $35.3 million in Q4 2015 was also attributable to a 31% reduction in sales volumes. Sales volumes were substantially down in the period due to the timing of Cook and Wytch Farm liftings as well as the absence of Athena and Anglia liftings, which as previously noted have been accounted for against the onerous contract provision recorded in Q4 2014, more than offsetting the increase in liftings from the Ythan field. Gas volumes, which accounted for only approximately 3% of total revenue in the period, were up marginally (3%) on the same period in 2014, although this was more than offset by lower realised prices ($19/boe in Q4 2015 compared to $28/boe in Q4 2014). Cost of sales decreased to $47.7 million in Q4 2015 (Q4 2014: $126.3 million) with significant reductions in operating costs, DD&A and movements in oil and gas inventory. The main drivers behind the $35.7 million decrease in operating costs to $23.1 million were: (i) the aforementioned exclusion of Athena and Anglia operating costs; (ii) absence of Beatrice and Jacky costs subsequent to re-transfer to Talisman in Q1 2015; and, (iii) supply chain cost reductions across the portfolio. The above resulted in Q4 2015 operating costs of $24/boe compared to $54/boe in Q4 2014. DD&A decreased significantly from $45.8 million in Q4 2014 to $27.0 million in Q4 2015. This reduction was mainly attributable to a different contributing field mix, notably the exclusion of the Beatrice and Jacky fields. The blended unit DD&A rate has been further reduced by the impairment write downs booked in 2014 as a consequence of the change in oil price environment. The blended rate for the quarter decreased from $42/boe in Q4 2014 to $26/boe in Q4 2015. Movement in inventory was a credit of $2.4 million compared to a charge of $21.7 million in Q4 2014. As noted above, movements in oil inventory arise due to differences between barrels produced and sold combined with changes in the valuation of the barrels held as inventory. In Q4 2015 fewer barrels of oil were sold (827kbbl) than produced (963kbbl), mainly as a result of the timing of Cook and Wytch Farm field liftings. This underlift more than offset the reduction in value of oil inventory over the quarter across all fields as a result of the fall in oil price. In Q4 2014 a significant reduction in the valuation of oil inventory combined with an excess of sales volumes over production volumes to produce a charge of $21.7 million.

21

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

QUARTERLY RESULTS SUMMARY $’000 Revenue

31 Dec 2015

30 Sep 2015

30 Jun 2015

31 Mar 2015

31 Dec 2014

30 Sep 2014

30 Jun 2014

31 Mar 2014

35,340

42,108

59,152

70,375

88,928

90,094

99,931

96,638

Profit/(Loss) After Tax

(177,625)

42,812

39,888

(26,078)

(49,517)

7,954

659

16,365

Earnings per share “EPS” – Basic1

(0.35)

0.13

0.12

(0.08)

(0.15)

0.02

0.00

0.05

EPS – Diluted1

(0.35)

0.13

0.12

(0.08)

(0.15)

0.02

0.00

0.05

411,384

329,519

329,519

329,519

329,519

329,519

328,399

326,195

Common shares outstanding (000) 12

Based on weighted average number of shares

The most significant factors to have affected the Company's results during the above quarters, other than transactions such as the acquisition of the Summit Asset, are fluctuations in underlying commodity prices and movement in production volumes. The Company has utilised forward sales contracts and foreign exchange contracts to take advantage of higher commodity prices and beneficial exchange rates while reducing the exposure to volatility. These contracts can cause volatility in profit after tax as a result of unrealised gains and losses due to movements in the oil price and USD: GBP exchange rate. In addition, the significant reduction in underlying commodity prices resulted in impairment write downs in Q4 2014 and Q4 2015 as noted above.

OUTSTANDING SHARE INFORMATION The Company’s common shares are traded on the Toronto Stock Exchange (“TSX”) in Canada under the symbol “IAE” and on the Alternative Investment Market (“AIM”) in the United Kingdom under the symbol “IAE”. As at 31 December 2015 Ithaca had 411,384,045 common shares outstanding along with 19,216,206 options outstanding to employees and directors to acquire common shares. In 2015 the Company’s Board of Directors granted 950,000 options at a weighted average exercise price of C$1.04. Each of the options granted may be exercised over a period of four years from the grant date. One third of the options will vest at the end of each of the first, second and third years from the effective date of grant. 31 December 2015 Common Shares Outstanding (1)

411,384,045

Share Price

$0.41 / Share

Total Market Capitalisation

$168,667,458

(1) Represents the TSX close price (CAD$0.57) on 31 December 2015. US$:CAD$ 0.72 on 31 December 2015

22

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

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 The consolidated financial statements include, from 31 July 2014 only (being the acquisition date), the consolidated financial statements of the Summit group of companies. 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.

23

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

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.

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MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

CONTROL ENVIRONMENT The Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of the Company's disclosure controls and procedures as at 31 December 2015, and concluded that such disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual filings, interim filings and other reports filed or submitted under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and such information is accumulated and communicated to the Company’s management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosures. The Chief Executive Officer and Chief Financial Officer have designed, or have caused such internal controls over financial reporting to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of the Company’s financial statements for external purposes in accordance with IFRS including those policies and procedures that: (a) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the Company’s assets; (b) are designed to provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with IFRS, and that receipts and expenditures of the Company are being made only in accordance with authorisations of management and directors of the Company; and (c) are designed to provide reasonable assurance regarding prevention or timely detection of unauthorised acquisition, use or disposition of the Company’s assets that could have a material effect on the annual financial statements or interim financial statements. The Chief Executive Officer and Chief Financial Officer performed an assessment of internal control over financial reporting as at 31 December 2015, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and concluded that internal control over financial reporting is effective with no material weaknesses identified. Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements and even those options determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. As of 31 December 2015, there were no changes in the Company’s internal control over financial reporting that occurred during the year ended 31 December 2015 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.

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MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

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. Net drawn debt noted above excludes any amounts outstanding under the Norwegian tax rebate facility that was repaid and retired on 8 July 2015.

Off Balance Sheet Arrangements

The Company has certain lease agreements and rig commitments which were entered into in the normal course of operations, all of which are disclosed under the heading "Commitments", above. Leases are treated as either operating leases or finance leases based on the extent to which risks and rewards incidental to ownership lie with the lessor or the lessee under IAS 17. Where appropriate, finance leases are recorded on the balance sheet. As at 31 December 2015, finance lease assets of $30.2 million and related liabilities of $30.3 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 2015 was $0.2 million (2014: $0.2 million). These transactions are in the normal course of business and are conducted on normal commercial terms with consideration comparable to those charged by third parties. As at 31 December 2015 the Company had loans receivable from FPF-1 Limited and FPU Services Limited, associates of the Company, for $60.8 million and $0.2 million, respectively (31 December 2014: $58.3 million and $Nil, respectively) as a result of the completion of the GSA transactions.

BOE Presentation

The calculation of boe is based on a conversion rate of six thousand cubic feet of natural gas ("mcf") to one barrel of crude oil ("bbl"). The term boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 mcf: 1 bbl, utilising a conversion ratio at 6 mcf: 1 bbl may be misleading as an indication of value.

Well Test Results

Certain well test results disclosed in this MD&A represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery therefrom. Full pressure transient and well test interpretation analyses have not been completed and as such the flow test results contained in this MD&A should be considered preliminary until such analyses have been completed.

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MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

RISKS AND UNCERTAINTIES The business of exploring for, developing and producing oil and natural gas reserves is inherently risky. There is substantial risk that the manpower and capital employed will not result in the finding of new reserves in economic quantities. There is a risk that the sale of reserves may be delayed due to processing constraints, lack of pipeline capacity or lack of markets. The Company is dependent upon the production rates and oil price to fund the current development program. For additional detail regarding the Company’s risks and uncertainties, refer to the Company’s Annual Information Form for the year ended 31 December 2015, (the “AIF”) filed on SEDAR at www.sedar.com. Commodity Price Volatility

RISK: The Company’s performance is significantly impacted by prevailing oil and natural gas prices, which are primarily driven by supply and demand as well as economic and political factors. MITIGATIONS: To mitigate the risk of fluctuations in oil and gas prices, the Company routinely executes commodity price derivatives, predominantly in relation to oil production, as a means of establishing a floor in realised prices.

Foreign Exchange Risk

RISK: The Company is exposed to financial risks including financial market volatility and fluctuation in various foreign exchange rates. MITIGATIONS: Given the proportion of development capital expenditure and operating costs incurred in currencies other than the US Dollar, the Company routinely executes hedges to mitigate foreign exchange rate risk on committed expenditure and/or draws debt in pounds sterling to settle sterling costs which will be repaid from surplus sterling generated revenues derived from Stella gas sales.

Interest Rate Risk

RISK: The Company is exposed to fluctuation in interest rates, particularly in relation to the debt facilities entered into. MITIGATIONS: To mitigate the fluctuations in interest rates, the Company routinely reviews the associated cost exposure and periodically executes hedges to lock in interest rates.

Debt Facility Risk

RISK: The Company is exposed to borrowing risks relating to drawdown of its debt facilities (the “Facilities”). The available debt capacity and ability to drawdown on the Facilities is based on the Company meeting certain covenants including coverage ratio tests, liquidity tests and development funding tests. The available debt capacity is redetermined semi-annually, using a detailed economic model of the Company and forward looking assumptions of which future oil and gas prices, costs and production profiles are key components. Movements in any component, including movements in forecast commodity prices can therefore have a significant impact on available debt capacity and limit the Company’s ability to borrow. There can be no assurance that the Company will satisfy such tests in the future in order to have access to adequate Facilities. The Facilities include covenants which restrict, among other things, the Company’s ability to incur additional debt or dispose of assets. As is standard to a credit facility, the Company's and Ithaca Energy (UK) Limited’s assets have been pledged as collateral and are subject to foreclosure in the event the Company or Ithaca Energy (UK) Limited defaults on the Facilities. MITIGATIONS: The financial tests necessary to draw down upon the Facilities needed were met during the period. The Company routinely produces detailed cashflow forecasts to monitor its compliance with the financial and liquidity tests of the Facilities and maintain the ability to execute proactive debt positive actions such as additional commodity hedging.

Financing Risk

RISK: To the extent cashflow from operations and the Facilities’ resources are ever deemed not adequate to fund Ithaca's cash requirements, external financing may be required. Lack of timely access to such additional financing, or access on unfavourable terms, could limit Ithaca's ability to make the necessary capital investments to maintain or expand its current business and to make necessary principal payments under the Facilities may be impaired. A failure to access adequate capital to continue its expenditure program may require that the Company meet any liquidity shortfalls through the selected divestment of all or a portion of its portfolio or result in delays to existing development programs. MITIGATIONS: The Company has established a business plan and routinely monitors its detailed cashflow forecasts and liquidity requirements to ensure it will continue to be fully funded. The Company believes that there are no circumstances that exist at present which require forced divestments, significant value destroying delays to existing programs or will likely lead to critical defaults relating to the Facilities. 27

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

Third Party Credit Risk

RISK: The Company is and may in the future be exposed to third party credit risk through its contractual arrangements with its current and future joint venture partners, marketers of its petroleum production and other parties. The Company extends unsecured credit to these and certain other parties, and therefore, the collection of any receivables may be affected by changes in the economic environment or other conditions affecting such parties. MITIGATIONS: Where appropriate, a cash call process is implemented with partners to cover high levels of anticipated capital expenditure thereby reducing any third party credit risk. The majority of the Company’s oil production is sold, depending on the field, to either Shell Trading International Ltd or BP Oil International Limited. Gas production is sold through contracts with RWE NPower PLC, Hartree Partners Power and Gas Company (UK) Limited, Shell UK Ltd. and Esso Exploration & Production UK Ltd. Each of these parties has historically demonstrated their ability to pay amounts owing to Ithaca.

Property Risk

RISK: The Company’s properties will be generally held in the form of licenses, concessions, permits and regulatory consents ("Authorisations"). The Company’s activities are dependent upon the grant and maintenance of appropriate Authorisations, which may not be granted; may be made subject to limitations which, if not met, will result in the termination or withdrawal of the Authorisation; or may be otherwise withdrawn. Also, in the majority of its licenses, the Company is a joint interest-holder with other third parties over which it has no control. An Authorisation may be revoked by the relevant regulatory authority if the other interest-holder is no longer deemed to be financially credible. There can be no assurance that any of the obligations required to maintain each Authorisation will be met. Although the Company believes that the Authorisations will be renewed following expiry or granted (as the case may be), there can be no assurance that such authorisations will be renewed or granted or as to the terms of such renewals or grants. The termination or expiration of the Company’s Authorisations may have a material adverse effect on the Company’s results of operations and business. MITIGATIONS: The Company has routine ongoing communications with the UK oil and gas regulatory body, the Department of Energy and Climate Change (“DECC”) as well as Norwegian authorities. Regular communication allows all parties to an Authorisation to be fully informed as to the status of any Authorisation and ensures the Company remains updated regarding fulfilment of any applicable requirements.

Operational Risk

RISK: The Company is subject to the risks associated with owning oil and natural gas properties, including environmental risks associated with air, land and water. All of the Company's operations are conducted offshore on the United Kingdom Continental Shelf and as such, Ithaca is exposed to operational risk associated with weather delays that can result in a material delay in project execution. Third parties operate some of the assets in which the Company has interests. As a result, the Company may have limited ability to exercise influence over the operations of these assets and their associated costs. The success and timing of these activities may be outside the Company's control. There are numerous uncertainties in estimating the Company’s reserve base due to the complexities in estimating the magnitude and timing of future production, revenue, expenses and capital. MITIGATIONS: The Company acts at all times as a reasonable and prudent operator and has nonoperated interests in assets where the designated operator is required to act in the same manner. The Company takes out market insurance to mitigate many of these operational, construction and environmental risks. The Company uses experienced service providers for the completion of work programmes. The Company uses the services of Sproule International Limited (“Sproule”) to independently assess the Company’s reserves on an annual basis.

Development Risk

RISK: The Company is executing development projects to produce reserves in off shore 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. 28

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015 Competition Risk

RISK: In all areas of the Company’s business, there is competition with entities that may have greater technical and financial resources. MITIGATIONS: The Company places appropriate emphasis on ensuring it attracts and retains high quality resources and sufficient financial resources to enable it to maintain its competitive position.

Weather Risk

RISK: In connection with the Company’s offshore operations being conducted in the North Sea, the Company is especially vulnerable to extreme weather conditions. Delays and additional costs which result from extreme weather can result in cost overruns, delays and, ultimately, in certain operations becoming uneconomic. MITIGATIONS: The Company takes potential delays as a result of adverse weather conditions into consideration in preparing budgets and forecasts and seeks to include an appropriate buffer in its all estimates of costs, which could be adversely affected by weather.

Reputation Risk

RISK: In the event a major offshore incident were to occur in respect of a property in which the Company has an interest, the Company's reputation could be severely harmed MITIGATIONS: The Company's operational activities are conducted in accordance with approved policies, standards and procedures, which are then passed on to the Company's subcontractors. In addition, Ithaca regularly audits its operations to ensure compliance with established policies, standards and procedures.

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MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

FORWARD-LOOKING INFORMATION Forward-Looking Information Advisories

This MD&A and any documents incorporated by reference herein contain certain forward-looking statements and forward-looking information which are based on the Company's internal expectations, estimates, projections, assumptions and beliefs as at the date of such statements or information, including, among other things, assumptions with respect to production, future capital expenditures, future acquisitions and dispositions and cash flow. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. The use of any of the words “forecasts”, "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe", "could", “scheduled”, “targeted”, “approximately” and similar expressions are intended to identify forward-looking statements and forward-looking information. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. The Company believes that the expectations reflected in those forwardlooking statements and information are reasonable but no assurance can be given that these expectations, or the assumptions underlying these expectations, will prove to be correct and such forward-looking statements and information included in this MD&A and any documents incorporated by reference herein should not be unduly relied upon. Such forward-looking statements and information speak only as of the date of this MD&A and any documents incorporated by reference herein and the Company does not undertake any obligation to publicly update or revise any forward-looking statements or information, except as required by applicable laws. In particular, this MD&A and any documents incorporated by reference herein, contains specific forward-looking statements and information pertaining to the following: • • • • •

The quality of and future net revenues from the Company’s reserves; Oil, natural gas liquids ("NGLs") and natural gas production levels; Commodity prices, foreign currency exchange rates and interest rates; Capital expenditure programs and other expenditures; Future operating costs;

• •

The sale, farming in, farming out or development of certain exploration properties using third party resources; Supply and demand for oil, NGLs and natural gas;

• • • • •

The Company’s ability to raise capital and the potential sources thereof; The continued availability of the Facilities; Funding requirements prior to Stella start up; Expected future net debt; The timing of Stella sail-away and first hydrocarbons;

• •

Stella production ramp up time following first hydrocarbons; 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 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; and Timing and cost of the development of the Company’s reserves; Estimates of production volumes and reserves in connection with acquisitions and certain projects

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 30

MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015 expected timeframe; • •

FDP approval and operational construction and development, both by the Company and its business partners, is obtained within expected timeframes; The Company’s development plan for its properties will be implemented as planned;

• • • •

The Company’s ability to keep operating during periods of harsh weather; Reserves volumes assigned to Ithaca’s properties; Ability to recover reserves volumes assigned to Ithaca’s properties; Revenues do not decrease significantly below anticipated levels and operating costs do not increase significantly above anticipated levels;

•

Future oil, NGLs and natural gas production levels from Ithaca’s properties and the prices obtained from the sales of such production;

• •

The level of future capital expenditure required to exploit and develop reserves; Ithaca’s ability to obtain financing on acceptable terms, in particular, the Company’s ability to access the Facilities;

• •

The continued ability of the Company to collect amounts receivable from third parties who Ithaca has provided credit to; Ithaca’s reliance on partners and their ability to meet commitments under relevant agreements; and,

•

The state of the debt and equity markets in the current economic environment.

The Company’s actual results could differ materially from those anticipated in these forward-looking statements and information as a result of assumptions proving inaccurate and of both known and unknown risks, including the risk factors set forth in this MD&A and under the heading "Risk Factors" in the AIF and the documents incorporated by reference herein, and those set forth below: • • • • • •

Risks associated with the exploration for and development of oil and natural gas reserves in the North Sea; Risks associated with offshore development and production including risks of inclement weather and the unavailability of transport facilities; Operational risks and liabilities that are not covered by insurance; Volatility in market prices for oil, NGLs and natural gas; The ability of the Company to fund its substantial capital requirements and operations and the terms of such funding; Risks associated with ensuring title to the Company’s properties;

•

Changes in environmental, health and safety or other legislation applicable to the Company’s operations, and the Company’s ability to comply with current and future environmental, health and safety and other laws;

•

The accuracy of oil and gas reserve estimates and estimated production levels as they are affected by the Company’s exploration and development drilling and estimated decline rates;

• • • • •

The Company’s success at acquisition, exploration, exploitation and development of reserves; Risks associated with realisation of anticipated benefits of acquisitions and dispositions; Risks related to changes to government policy with regard to offshore drilling; The Company’s reliance on key operational and management personnel; The ability of the Company to obtain and maintain all of its required permits and licenses;

•

Competition for, among other things, capital, drilling equipment, acquisitions of reserves, undeveloped lands and skilled personnel; Changes in general economic, market and business conditions in Canada, North America, the United Kingdom, Europe and worldwide; Actions by governmental or regulatory authorities including changes in income tax laws or changes in tax laws, royalty rates and incentive programs relating to the oil and gas industry including any increase in UK or Norwegian taxes;

• •

• •

Adverse regulatory or court rulings, orders and decisions; and, Risks associated with the nature of the common shares.

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MANAGEMENT DISCUSSION & ANALYSIS YEAR ENDED 31 DECEMBER 2015

Additional Reader Advisories

Reserves Disclosure Advisories

The information in this MD&A is provided as of 21 March 2016. The 2015 results have been compared to the results of 2014. This MD&A should be read in conjunction with the Company’s audited consolidated financial statements as at 31 December 2015 and 2014 together with the accompanying notes and Annual Information Form (“AIF”) for the year ended 31 December 2015. These documents, and additional information regarding Ithaca, are available electronically from the Company’s website (www.ithacaenergy.com) or SEDAR profile at www.sedar.com. With respect to Ithaca’s reserves disclosure, the figures are derived from a report prepared by Sproule, an independent qualified reserves evaluator, evaluating the reserves of Ithaca as of 31 December 2015 and forming the basis for the Statement of Reserves Data and Other Oil and Gas information of Ithaca dated 22 March 2016 (the “Statement”). The reserves estimates of Ithaca are based on the Canadian Oil and Gas Evaluation Handbook (“COGEH”) pursuant to Canadian Securities Administrators’ National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities, with references to oil referring to medium quality oil. If a discovery is made, there is no certainty that it will be developed, or if it is developed, there is no certainty as to the timing of such development or the benefits (if any), which may flow to the Company. Cashflow from operations includes the impact of executed hedges and does not include non-cash items such as DD&A, revaluation of financial instruments, impairments of fixed assets and movements in goodwill, which may have a significant impact on the Company’s results. Statements relating to reserves are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

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